Duke Energy CORP (Form: 10-Q, Received: 08/09/2006 17:20:57)

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2006 Or

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission file number 1-32853

DUKE ENERGY CORPORATION

(Formerly Duke Energy Holding Corp.)

(Exact Name of Registrant as Specified in its Charter)


Delaware		20-2777218
(State or Other Jurisdiction of Incorporation)		(IRS Employer Identification No.)

526 South Church Street Charlotte, NC		28202-1803
(Address of Principal Executive Offices)		(Zip Code)

704-594-6200

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer (as defined in Rule 12b-2 of the Securities Exchange Act of 1934).

Large accelerated filer x Accelerated filer ¨ Non-accelerated filer ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Securities Exchange Act of 1934). Yes ¨ No x

Indicate the number of shares outstanding of each of the Issuer’s classes of common stock, as of the latest practicable date.


Number of shares of Common Stock, par value $0.001, outstanding as of August 4, 2006		1,253,011,563

INDEX

DUKE ENERGY CORPORATION

FORM 10-Q FOR THE QUARTER ENDED

JUNE 30, 2006


Item		Page
PART I. FINANCIAL INFORMATION

1.	Financial Statements	3
	Unaudited Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2006 and 2005 .	3
	Unaudited Consolidated Balance Sheets as of June 30, 2006 and December 31, 2005	4
	Unaudited Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2006 and 2005	6
	Unaudited Consolidated Statements of Common Stockholders’ Equity and Comprehensive Income (Loss) for the Three and Six Months Ended June 30, 2006 and 2005	7
	Unaudited Notes to Consolidated Financial Statements	8

2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	49

3.	Quantitative and Qualitative Disclosures About Market Risk	70

4.	Controls and Procedures	72

PART II. OTHER INFORMATION

1.	Legal Proceedings	73

1A.	Risk Factors	73

2.	Unregistered Sales of Equity Securities and Use of Proceeds	73

4.	Submission of Matters to a Vote of Security Holders	73

6.	Exhibits	74

	Signatures	76

SAFE HARBOR STATEMENT UNDER THE PRIVATE

SECURITIES LITIGATION REFORM ACT OF 1995

Duke Energy Corporation’s (Duke Energy) reports, filings and other public announcements may contain or incorporate by reference statements that do not directly or exclusively relate to historical facts. Such statements are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. You can typically identify forward-looking statements by the use of forward-looking words, such as “may,” “will,” “could,” “project,” “believe,” “anticipate,” “expect,” “estimate,” “continue,” “potential,” “plan,” “forecast” and other similar words. Those statements represent Duke Energy’s intentions, plans, expectations, assumptions and beliefs about future events and are subject to risks, uncertainties and other factors. Many of those factors are outside Duke Energy’s control and could cause actual results to differ materially from the results expressed or implied by those forward-looking statements. Those factors include the risk factors set forth in Item 1A of the Form 10-K of Duke Energy and of Cinergy Corp. (Cinergy) for the year ended December 31, 2005, as updated in their respective Form 10-Q for the period ended March 31, 2006, as well as the following:

•

State, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rate structures, and affect the speed at and degree to which competition enters the electric and natural gas industries

•

The outcomes of litigation and regulatory investigations, proceedings or inquiries

•

Industrial, commercial and residential growth in Duke Energy’s service territories

•

Additional competition in electric or gas markets and continued industry consolidation

•

Political and regulatory uncertainty in other countries in which Duke Energy conducts business

•

The influence of weather and other natural phenomena on company operations, including the economic, operational and other effects of hurricanes and ice storms

•

The timing and extent of changes in commodity prices, interest rates and foreign currency exchange rates

•

General economic conditions, including any potential effects arising from terrorist attacks and any consequential hostilities or other hostilities

•

Changes in environmental and other laws and regulations to which Duke Energy and its subsidiaries are subject

•

The results of financing efforts, including Duke Energy’s ability to obtain financing on favorable terms, which can be affected by various factors, including Duke Energy’s credit ratings and general economic conditions

•

Declines in the market prices of equity securities and resultant cash funding requirements for Duke Energy’s defined benefit pension plans

•

The level of creditworthiness of counterparties to Duke Energy’s transactions

•

The amount of collateral required to be posted from time to time in Duke Energy’s transactions

•

Growth in opportunities for Duke Energy’s business units, including the timing and success of efforts to develop domestic and international power, pipeline, gathering, processing and other projects

•

The performance of electric generation, pipeline and gas processing facilities and of projects undertaken by Duke Energy’s non-regulated businesses

•

The extent of success in connecting natural gas supplies to gathering and processing systems and in connecting and expanding gas and electric markets

•

The effect of accounting pronouncements issued periodically by accounting standard-setting bodies

•

Conditions of the capital markets and equity markets during the periods covered by the forward-looking statements and

•

The ability to successfully complete merger, acquisition or divestiture plans, including the prices at which Duke Energy is able to sell assets; regulatory or other limitations imposed as a result of a merger, acquisition or divestiture; and the success of the business following a merger, acquisition or divestiture

In light of these risks, uncertainties and assumptions, the events described in the forward-looking statements might not occur or might occur to a different extent or at a different time than Duke Energy has described. Duke Energy undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

PART I FINANCIAL INFORMATION

DUKE ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(In millions, except per-share amounts)


	Three Months Ended June 30,						Six Months Ended June 30,
	2006			2005			2006			2005
Operating Revenues
Non-regulated electric, natural gas, natural gas liquids and other	$	985		$	3,305		$	1,581		$	6,206
Regulated electric		2,030			1,226			3,316			2,485
Regulated natural gas and natural gas liquids		958			743			2,277			1,911
Total operating revenues		3,973			5,274			7,174			10,602
Operating Expenses
Natural gas and petroleum products purchased		431			2,613			1,169			5,363
Operation, maintenance and other		1,195			894			1,952			1,702
Fuel used in electric generation and purchased power		971			392			1,370			741
Depreciation and amortization		564			462			960			943
Property and other taxes		202			145			350			298
Impairment and other charges		—			2			—			123
Total operating expenses		3,363			4,508			5,801			9,170
Gains on Sales of Investments in Commercial and Multi-Family Real Estate		145			12			171			54
(Losses) Gains on Sales of Other Assets and Other, net		(11	)		—			22			9
Operating Income		744			778			1,566			1,495
Other Income and Expenses
Equity in earnings of unconsolidated affiliates		194			39			369			80
(Losses) Gains on sales and impairments of equity investments		(20	)		6			(20	)		1,245
Other income and expenses, net		46			35			58			59
Total other income and expenses		220			80			407			1,384

Interest Expense		339			295			589			585
Minority Interest Expense		15			78			30			498
Earnings From Continuing Operations Before Income Taxes		610			485			1,354			1,796
Income Tax Expense from Continuing Operations		175			157			433			608
Income From Continuing Operations		435			328			921			1,188
Loss From Discontinued Operations, net of tax		(80	)		(19	)		(208	)		(11	)
Net Income		355			309			713			1,177

Dividends and Premiums on Redemption of Preferred and Preference Stock		—			2			—			4
Earnings Available For Common Stockholders	$	355		$	307		$	713		$	1,173

Common Stock Data
Weighted-average shares outstanding
Basic		1,238			927			1,083			941
Diluted		1,259			964			1,111			977
Earnings per share (from continuing operations)
Basic	$	0.35		$	0.35		$	0.85		$	1.26
Diluted	$	0.34		$	0.34		$	0.83		$	1.21
Loss per share (from discontinued operations)
Basic	$	(0.06	)	$	(0.02	)	$	(0.19	)	$	(0.01	)
Diluted	$	(0.06	)	$	(0.02	)	$	(0.19	)	$	(0.01	)
Earnings per share
Basic	$	0.29		$	0.33		$	0.66		$	1.25
Diluted	$	0.28		$	0.32		$	0.64		$	1.20
Dividends per share	$	0.63		$	0.585		$	0.94		$	0.86

See Notes to Unaudited Consolidated Financial Statements

PART I

DUKE ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In millions)


	June 30, 2006		December 31, 2005
ASSETS
Current Assets
Cash and cash equivalents	$	752	$	511
Short-term investments		254		632
Receivables (net of allowance for doubtful accounts of $161 at June 30, 2006 and $127 at December 31, 2005)		2,253		2,580
Inventory		1,201		863
Assets held for sale		1,309		1,528
Unrealized gains on mark-to-market and hedging transactions		93		87
Other		953		1,756
Total current assets		6,815		7,957
Investments and Other Assets
Investments in unconsolidated affiliates		2,516		1,933
Nuclear decommissioning trust funds		1,588		1,504
Goodwill		8,042		3,775
Intangibles, net		1,048		65
Notes receivable		268		138
Unrealized gains on mark-to-market and hedging transactions		154		62
Assets held for sale		635		3,597
Investments in residential, commercial and multi-family real estate (net of accumulated depreciation of $18 at June 30, 2006 and $17 at December 31, 2005)		1,382		1,281
Other		3,140		2,678
Total investments and other assets		18,773		15,033
Property, Plant and Equipment
Cost		57,340		40,823
Less accumulated depreciation and amortization		16,445		11,623
Net property, plant and equipment		40,895		29,200
Regulatory Assets and Deferred Debits
Deferred debt expense		331		269
Regulatory assets related to income taxes		1,356		1,338
Other		2,198		926
Total regulatory assets and deferred debits		3,885		2,533
Total Assets	$	70,368	$	54,723

See Notes to Unaudited Consolidated Financial Statements

PART I

DUKE ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS—(Continued)

(Unaudited)

(In millions, except per-share amounts)


	June 30, 2006		December 31, 2005
LIABILITIES AND COMMON STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable	$	1,470	$	2,431
Notes payable and commercial paper		1,272		83
Taxes accrued		487		327
Interest accrued		306		230
Liabilities associated with assets held for sale		885		1,488
Current maturities of long-term debt		1,371		1,400
Unrealized losses on mark-to-market and hedging transactions		250		204
Other		2,029		2,255
Total current liabilities		8,070		8,418
Long-term Debt		18,574		14,547
Deferred Credits and Other Liabilities
Deferred income taxes		7,076		5,253
Investment tax credit		226		144
Unrealized losses on mark-to-market and hedging transactions		117		10
Liabilities associated with assets held for sale		444		2,085
Asset retirement obligations		2,185		2,058
Other		7,261		5,020
Total deferred credits and other liabilities		17,309		14,570
Commitments and Contingencies
Minority Interests		745		749
Common Stockholders’ Equity
Common stock, $0.001 par value, 2 billion shares authorized; 1,252 million and zero shares outstanding at June 30, 2006 and December 31, 2005, respectively		1		—
Common stock, no par, 2 billion shares authorized; zero and 928 million shares outstanding at June 30, 2006 and December 31, 2005, respectively		—		10,446
Additional paid-in capital		19,715		—
Retained earnings		4,907		5,277
Accumulated other comprehensive income		1,047		716
Total common stockholders’ equity		25,670		16,439
Total Liabilities and Common Stockholders’ Equity	$	70,368	$	54,723

See Notes to Unaudited Consolidated Financial Statements

PART I

DUKE ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In millions)


	Six Months Ended June 30,
	2006			2005
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	713		$	1,177
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization (including amortization of nuclear fuel)		1,042			1,081
Gains on sales of investments in commercial and multi-family real estate		(171	)		(54	)
Gains on sales of equity investments and other assets		(6	)		(1,281	)
Impairment charges		20			123
Deferred income taxes		301			244
Minority Interest		30			484
Equity in earnings of unconsolidated affiliates		(369	)		(80	)
Purchased capacity levelization		(4	)		(5	)
Contribution to company-sponsored pension plans		(23	)		(21	)
(Increase) decrease in
Net realized and unrealized mark-to-market and hedging transactions		(153	)		17
Receivables		1,182			286
Inventory		144			(11	)
Other current assets		1,249			(46	)
Increase (decrease) in
Accounts payable		(1,730	)		(175	)
Taxes accrued		(57	)		332
Other current liabilities		(1,138	)		(65	)
Capital expenditures for residential real estate		(240	)		(209	)
Cost of residential real estate sold		86			109
Other, assets		471			(106	)
Other, liabilities		97			228
Net cash provided by operating activities		1,444			2,028
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures		(1,393	)		(1,062	)
Investment expenditures		(63	)		(24	)
Acquisitions, net of cash acquired		(89	)		—
Cash acquired from acquisition of Cinergy		147			—
Purchases of available-for-sale securities		(13,479	)		(20,787	)
Proceeds from sales and maturities of available-for-sale securities		13,705			20,987
Net proceeds from the sales of equity investments and other assets, and sales of and collections on notes receivable		1,597			1,341
Proceeds from the sales of commercial and multi-family real estate		221			77
Settlement of net investment hedges and other investing derivatives		(89	)		(162	)
Purchases of emission allowances		(112	)		—
Sales of emission allowances		82			—
Other		(60	)		(8	)
Net cash provided by investing activities		467			362
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from the:
Issuance of long-term debt		335			4
Issuance of common stock and common stock related to employee benefit plans		41			28
Payments for the redemption of:
Long-term debt		(1,014	)		(639	)
Preferred stock of a subsidiary		(12	)		—
Increase in overdrafts		24			—
Notes payable and commercial paper		170			167
Distributions to minority interests		(231	)		(377	)
Contributions from minority interests		184			330
Dividends paid		(681	)		(522	)
Repurchase of common shares		(500	)		(909	)
Other		14			3
Net cash used in financing activities		(1,670	)		(1,915	)
Changes in cash and cash equivalents included in assets held for sale		—			1
Net increase in cash and cash equivalents		241			476
Cash and cash equivalents at beginning of period		511			533
Cash and cash equivalents at end of period	$	752		$	1,009

Supplemental Disclosures
Acquisition of Cinergy Corp.
Fair value of assets acquired	$	17,638		$	—
Liabilities assumed	$	12,838		$	—
Issuance of common stock	$	8,993		$	—

Significant non-cash transactions:
Conversion of convertible notes to stock	$	611		$	—
Dividends declared but not paid	$	402		$	287
AFUDC—equity component	$	26		$	9

See Notes to Unaudited Consolidated Financial Statements

PART I

DUKE ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY

AND COMPREHENSIVE INCOME (LOSS)

(Unaudited)

(In millions)


												Accumulated Other Comprehensive Income (Loss)
	Common Stock Shares		Common Stock			Additional Paid-in Capital			Retained Earnings			Foreign Currency Adjustments		Net Gains (Losses) on Cash Flow Hedges			Minimum Pension Liability Adjustment			Other			Total
Balance December 31, 2004	957		$	11,266		$	—		$	4,525		$	540	$	526		$	(416	)	$	—		$	16,441
Net income	—			—			—			868			—		—			—			—			868
Other Comprehensive Income
Foreign currency translation adjustments (a)	—			—			—			—			47		—			—			—			47
Net unrealized gains on cash flow hedges (b)	—			—			—			—			—		143			—			—			143
Reclassification into earnings from cash flow hedges (c)	—			—			—			—			—		59			—			—			59

Total comprehensive income																								1,117
Dividend reinvestment and employee benefits	1			25			—			—			—		—			—			—			25
Stock repurchase	(30	)		(834	)		—			—			—		—			—			—			(834	)
Common stock dividends	—			—			—			(263	)		—		—			—			—			(263	)
Preferred and preference stock dividends	—			—			—			(2	)		—		—			—			—			(2	)
Balance March 31, 2005	928		$	10,457		$	—		$	5,128		$	587	$	728		$	(416	)	$	—		$	16,484
Net income	—			—			—			309			—		—			—			—			309
Other Comprehensive Income
Foreign currency translation adjustments	—			—			—			—			9		—			—			—			9
Net unrealized gains on cash flow hedges (b)	—			—			—			—			—		93			—			—			93
Reclassification into earnings from cash flow hedges (c)	—			—			—			—			—		(57	)		—			—			(57	)

Total comprehensive income																								354
Dividend reinvestment and employee benefits	1			30			—			—			—		—			—			—			30
Stock repurchase	(3	)		(75	)		—			—			—		—			—			—			(75	)
Common stock dividends	—			—			—			(542	)		—		—			—			—			(542	)
Preferred and preference stock dividends	—			—			—			(2	)		—		—			—			—			(2	)
Other capital stock transactions, net	—			—			—			32			—		—			—			—			32
Balance June 30, 2005	926		$	10,412		$	—		$	4,925		$	596	$	764		$	(416	)	$	—		$	16,281

Balance December 31, 2005	928		$	10,446		$	—		$	5,277		$	846	$	(87	)	$	(60	)	$	17		$	16,439
Net income	—			—			—			358			—		—			—			—			358
Other Comprehensive Income
Foreign currency translation adjustments	—			—			—			—			59		—			—			—			59
Net unrealized gains on cash flow hedges (b)	—			—			—			—			—		5			—			—			5
Reclassification into earnings from cash flow hedges (c)	—			—			—			—			—		11			—			—			11
Other (d)	—			—			—			—			—		—			—			16			16

Total comprehensive income																								449
Dividend reinvestment and employee benefits	1			22			—			—			—		—			—			—			22
Stock repurchase	(2	)		(69	)		—			—			—		—			—			—			(69	)
Common stock dividends	—			—			—			(289	)		—		—			—			—			(289	)
Balance March 31, 2006	927		$	10,399		$	—		$	5,346		$	905	$	(71	)	$	(60	)	$	33		$	16,552
Net income	—			—			—			355			—		—			—			—			355
Other Comprehensive Income
Foreign currency translation adjustments	—			—						—			252		—			—			—			252
Net unrealized losses on cash flow hedges (b)	—			—			—			—			—		(8	)		—			—			(8	)
Reclassification into earnings from cash flow hedges (c)	—			—			—			—			—		6			—			—			6
Other (d)	—			—			—			—			—		—			—			(10	)		(10	)

Total comprehensive income																								595
Retirement of Old Duke Energy shares	(927	)		(10,399	)		—			—			—		—			—			—			(10,399	)
Issuance of New Duke Energy shares	927			1			10,398			—			—		—			—			—			10,399
Common stock issued in connection with Cinergy merger	313			—			8,993			—			—		—			—			—			8,993
Conversion of Cinergy options to Duke Energy options	—			—			59			—			—		—			—			—			59
Dividend reinvestment and employee benefits	1			—			50			—			—		—			—			—			50
Stock repurchase	(15	)		—			(431	)		—			—		—			—			—			(431	)
Common stock dividends	—			—			—			(794	)		—		—			—			—			(794	)
Conversion of debt to equity	26			—			611			—			—		—			—			—			611
Tax benefit due to conversion of debt to equity	—			—			32			—			—		—			—			—			32
Other capital stock transactions, net	—			—			3			—			—		—			—			—			3
Balance June 30, 2006	1,252		$	1		$	19,715		$	4,907		$	1,157	$	(73	)	$	(60	)	$	23		$	25,670

(a)

Foreign currency translation adjustments, net of $62 tax benefit for the three months ended March 31, 2005. The 2005 tax benefit related to the settled net investment hedges (see Note 15). Substantially all of the 2005 tax benefit is a correction of an immaterial accounting error related to prior periods.

(b)	Net unrealized gains on cash flow hedges, net of $9 tax benefit and $49 tax expense for the three months ended June 30, 2006 and 2005, respectively, and $3 and $74 tax expense for the three months ended March 31, 2006 and 2005, respectively.

(c)

Reclassification into earnings from cash flow hedges, net of $7 tax expense and $29 tax benefit for the three months ended June 30, 2006 and 2005, respectively, and $7 and $30 tax expense for the three months ended March 31, 2006 and 2005, respectively. Reclassification into earnings from cash flow hedges for the three months ended March 31, 2006, is due primarily to the recognition of Duke Energy North America’s (DENA’s) unrealized net gains related to hedges on forecasted transactions which will no longer occur as a result of the plan to sell or otherwise dispose of substantially all of DENA’s assets and contracts outside of the Midwestern United States and certain contractual positions related to the Midwestern assets (see Notes 13 and 15).

(d)	Net of $4 tax benefit for the three months ended June 30, 2006, and $8 tax expense for the three months ended March 31, 2006.

See Notes to Unaudited Consolidated Financial Statements

PART I

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements

(Unaudited)

1. Basis of Presentation

Nature of Operations and Basis of Consolidation. Duke Energy Corporation (collectively with its subsidiaries, Duke Energy), is a leading energy company located in the Americas with a real estate subsidiary. These Consolidated Financial Statements include, after eliminating intercompany transactions and balances, the accounts of Duke Energy and all majority-owned subsidiaries where Duke Energy has control, and those variable interest entities where Duke Energy is the primary beneficiary. These Consolidated Financial Statements also reflect Duke Energy’s 12.5% undivided interest in the Catawba Nuclear Station.

Duke Energy Holding Corp. (Duke Energy HC) was incorporated in Delaware on May 3, 2005 as Deer Holding Corp., a wholly-owned subsidiary of Duke Energy Corporation (Old Duke Energy). On April 3, 2006, in accordance with their previously announced merger agreement, Old Duke Energy and Cinergy Corp. (Cinergy) merged into wholly-owned subsidiaries of Duke Energy HC, resulting in Duke Energy HC becoming the parent entity. In connection with the closing of the merger transactions, Duke Energy HC changed its name to Duke Energy Corporation (New Duke Energy or Duke Energy) and Old Duke Energy converted into a limited liability company named Duke Power Company LLC. As a result of the merger transactions, each outstanding share of Cinergy common stock was converted into 1.56 shares of common stock of Duke Energy, which resulted in the issuance of approximately 313 million shares. Additionally, each share of common stock of Old Duke Energy was converted into one share of Duke Energy common stock. Old Duke Energy is the predecessor of Duke Energy for purposes of U.S. securities regulations governing financial statement filing. Therefore, the accompanying Consolidated Financial Statements reflect the results of operations of Old Duke Energy for the three months ended March 31, 2006 and the three and six months ended June 30, 2005 and the financial position of Old Duke Energy as of December 31, 2005. New Duke Energy had separate operations for the period beginning with the quarter ended June 30, 2006, and references to amounts for periods after the closing of the merger relate to New Duke Energy. Cinergy’s results have been included in the accompanying Consolidated Statements of Operations from the date of acquisition and thereafter (see “Cinergy Merger” in Note 2). Both Old Duke Energy and New Duke Energy are referred to as Duke Energy herein.

Shares of common stock of New Duke Energy carry a stated par value of $0.001, while shares of common stock of Old Duke Energy had been issued at no par. In April 2006, as a result of the conversion of all outstanding shares of Old Duke Energy common stock to New Duke Energy common stock, the par value of the shares issued was recorded in Common Stock within Common Stockholders’ Equity in the Consolidated Balance Sheets and the excess of issuance price over stated par value was recorded in Additional Paid-in Capital within Common Stockholders’ Equity in the Consolidated Balance Sheets. Prior to the conversion of common stock from shares of Old Duke Energy to New Duke Energy, all proceeds from issuances of common stock were solely reflected in Common Stock within Common Stockholders’ Equity in the Consolidated Balance Sheets.

These Consolidated Financial Statements reflect all normal recurring adjustments that are, in the opinion of management, necessary to fairly present Duke Energy’s financial position and results of operations. Amounts reported in the interim Consolidated Statements of Operations are not necessarily indicative of amounts expected for the respective annual periods due to the effects of seasonal temperature variations on energy consumption, the timing of maintenance on electric generating units, changes in mark-to-market valuations, changing commodity prices and other factors. These Consolidated Financial Statements and other information included in this quarterly report should be read in conjunction with the Consolidated Financial Statements and Notes in Duke Energy’s Form 10-K for the year ended December 31, 2005.

Effective July 1, 2005, Duke Energy deconsolidated Duke Energy Field Services, LLC (DEFS) due to a reduction in ownership and its inability to exercise control over DEFS. DEFS has been accounted for as an equity method investment since July 1, 2005.

Use of Estimates. To conform with generally accepted accounting principles (GAAP) in the United States, management makes estimates and assumptions that affect the amounts reported in the Consolidated Financial Statements and Notes To Consolidated Financial Statements. Although these estimates are based on management’s best available knowledge at the time, actual results could differ.

Reclassifications. As discussed further in Note 14, as a result of the merger with Cinergy, effective in the second quarter of 2006, Duke Energy adopted new business segments and certain prior period amounts have been recast to conform to the new segment presentation. Certain other prior period amounts within the Consolidated Statements of Cash Flows have been reclassified to conform to the presentation for the current period.

PART I

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

Excise Taxes . Certain excise taxes levied by state or local governments are collected by Duke Energy from its customers. These taxes, which are required to be paid regardless of Duke Energy’s ability to collect from the customer, are accounted for on a gross basis. When Duke Energy acts as an agent, and the tax is not required to be remitted if it is not collected from the customer, the taxes are accounted for on a net basis. Duke Energy’s excise taxes accounted for on a gross basis and recorded as revenues in the accompanying Consolidated Statements of Operations for the three and six months ended June 30, 2006 and 2005 were as follows:


	Three Months Ended June 30, 2006		Three Months Ended June 30, 2005		Six Months Ended June 30, 2006		Six Months Ended June 30, 2005
	(in millions)
Excise Taxes	$	61	$	27	$	91	$	56

2. Acquisitions and Dispositions

Acquisitions. Duke Energy consolidates assets and liabilities from acquisitions as of the purchase date, and includes earnings from acquisitions in consolidated earnings after the purchase date. Assets acquired and liabilities assumed are recorded at estimated fair values on the purchase date. The purchase price minus the estimated fair value of the acquired assets and liabilities meeting the definition of a business as defined in EITF Issue No. 98-3, “Determining Whether a Nonmonetary Transaction Involves Receipt of Productive Assets or of a Business” is recorded as goodwill. The allocation of the purchase price may be adjusted if additional information on known contingencies existing at the date of acquisition becomes available during the allocation period, which generally does not exceed one year from the consummation date, however, it may be longer for certain income tax items.

Cinergy Merger. On April 3, 2006, the previously announced merger between Duke Energy and Cinergy was consummated (see Note 1 for additional information). For accounting purposes, the effective date of the merger was April 1, 2006. The merger combines the Duke Energy and Cinergy regulated franchises as well as deregulated generation in the Midwestern United States. The merger is anticipated to provide more regulatory, geographic and weather diversity to Duke Energy’s earnings. See Note 16 for discussion of regulatory impacts of the merger.

The merger has been accounted for under the purchase method of accounting with Duke Energy treated as the acquirer for accounting purposes. As a result, the assets and liabilities of Cinergy were recorded at their respective fair values as of April 3, 2006 and the results of Cinergy’s operations are included in the Duke Energy consolidated financial statements beginning as of the merger date. Except for an adjustment related to pension and other postretirement benefit obligations, as mandated by Statement of Financial Accounting Standards (SFAS) No. 87, “Employers’ Accounting for Pensions” and SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions,” the accompanying consolidated financial statements do not reflect any pro forma adjustments related to Cinergy’s regulated operations that are accounted for pursuant to SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation,” which are comprised of The Cincinnati Gas & Electric Company’s (CG&E) regulated transmission and distribution, PSI Energy, Inc. (PSI) and The Union Light, Heat and Power Company (ULH&P). Under the rate setting and recovery provisions currently in place for these regulated operations which provide revenues derived from cost, the fair values of the individual tangible and intangible assets and liabilities are considered to approximate their carrying values.

The fair values of the assets acquired and liabilities assumed are preliminary and are subject to change as valuation analyses are finalized and remaining information on the fair values is received. However, Duke Energy does not currently anticipate any such changes to have a material impact on Duke Energy’s consolidated results of operations, cash flows or financial position.

In connection with the merger, Duke Energy issued 1.56 shares of Duke Energy common stock for each outstanding share of Cinergy common stock, which resulted in the issuance of approximately 313 million shares of Duke Energy common stock. Based on the market price of Duke Energy common stock during the period including the two trading days before through the two trading days after May 9, 2005, the date Duke Energy and Cinergy announced the merger, the transaction is valued at approximately $9.1 billion and has resulted in preliminary incremental goodwill to Duke Energy of approximately $4.3 billion. The amount of goodwill results from significant strategic and financial benefits to the company including:

•

increased financial strength and flexibility;

•

stronger utility business platform;

•

greater scale and fuel diversity, as well as improved operational efficiencies for the merchant generation business;

•

broadened electric distribution platform;

PART I

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

•

improved reliability and customer service through the sharing of best practices;

•

increased scale and scope of the electric and gas businesses with stand-alone strength;

•

complementary positions in the Midwest;

•

greater customer diversity;

•

combined expertise; and

•

significant cost savings synergies.

The following table summarizes the estimated fair values of the assets acquired and liabilities assumed at the date of acquisition:

Purchase Price Allocation


	April 3, 2006
	(in millions)
Purchase price	$	9,089

Current assets		2,642
Investments and other assets		1,610
Property, plant and equipment ^(a)		10,897
Intangible assets		1,092
Regulatory assets and deferred debits		1,397

Total assets acquired		17,638
Current liabilities		4,132
Long-term debt		4,295
Deferred credits and other liabilities		4,400
Minority interests		11

Net assets acquired		4,800

Preliminary goodwill	$	4,289

(a)	Amounts recorded for regulated property, plant and equipment by Duke Energy on the acquisition date include approximately $3,995 million related to accumulated deprecation of acquired assets.

Goodwill recorded as of June 30, 2006 resulting from Duke Energy’s merger with Cinergy is $4,289 million, none of which is deductible for income tax purposes. Of this amount, approximately $161 million has been allocated to assets held for sale related to the disposition of Cinergy Marketing and Trading, LP, and Cinergy Canada, Inc. (see Note 13). The valuation and other assessment procedures required to allocate this goodwill to the appropriate reporting units and reportable segments is currently in process and is anticipated to be completed during 2006. While the allocation is not yet complete, Duke Energy anticipates that the goodwill will be allocated to the U.S. Franchised Electric and Gas and Commercial Power segments, as well as Other, and the majority of the goodwill will be allocated to the U.S. Franchised Electric and Gas segment (see Note 9).

The following unaudited consolidated pro forma financial results are presented as if the Cinergy merger had occurred at the beginning of each of the periods presented:

Unaudited Consolidated Pro Forma Results


	Three Months Ended June 30, 2005		Six Months Ended June 30,
	Three Months Ended June 30, 2005		2006		2005
	(in millions, except per share amounts)
Operating revenues	$	6,329	$	8,819	$	12,911
Income from continuing operations		347		955		1,268
Net income		333		765		1,291
Earnings available for common stockholders		331		765		1,287

Earnings per share (from continuing operations)
Basic	$	0.28	$	0.77	$	1.01
Diluted	$	0.27	$	0.75	$	0.99

Earnings per share
Basic	$	0.27	$	0.61	$	1.03
Diluted	$	0.26	$	0.60	$	1.00

PART I

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

Pro forma results for the six months ended June 30, 2006 include approximately $78 million of charges related to costs to achieve the merger and related synergies, which are recorded within Operating Expenses on the Consolidated Statements of Operations. Pro forma results for the three months ended June 30, 2006 are not presented since the merger occurred at the beginning of the period presented and do not include any significant transactions completed by Duke Energy other than the merger with Cinergy. The pre-tax impacts of purchase accounting on the results of operations of Duke Energy are expected to be charges of approximately $130 million to $140 million during 2006.

Other Acquisitions. During the first quarter of 2006, Duke Energy International (DEI) closed on two transactions which resulted in the acquisition of an additional 27% interest in the Aguaytia Integrated Energy Project (Aguaytia), located in Peru, for approximately $31 million (approximately $18 million net of cash acquired). The project’s scope includes the production and processing of natural gas, sale of liquefied petroleum gas (LPG) and natural gas liquids and the generation, transmission and sale of electricity from a 177 megawatt power plant. These acquisitions increased DEI’s ownership in Aguaytia to 65% and resulted in Duke Energy accounting for Aguaytia as a consolidated entity. Prior to the acquisition of this additional interest, Aguaytia was accounted for as an equity method investment.

During the first quarter of 2006, Duke Energy North America (DENA) acquired the remaining 33 1/3% interest in Bridgeport Energy LLC (Bridgeport) from United Bridgeport Energy LLC (UBE) for approximately $71 million. The assets and liabilities of Bridgeport, which had been classified as Assets Held For Sale, were included as part of DENA’s power generation assets which were sold to a subsidiary of LS Power Equity Partners (LS Power) (see Note 13).

In May 2006, Duke Energy announced an agreement to acquire an approximate 825 megawatt power plant located in Rockingham County, North Carolina, from Dynegy for approximately $195 million. The Rockingham plant is a peaking power plant used during times of high electricity demand, generally in the winter and summer months and consists of five 165 megawatt Westinghouse combustion turbine units capable of using either natural gas or oil to operate. The acquisition is consistent with Duke Energy’s plan to meet customers’ electric needs over the next twenty years. The transaction, which is anticipated to close in the fourth quarter of 2006, requires approvals by the North Carolina Utilities Commission (NCUC) and the Federal Energy Regulatory Commission (FERC). In addition, approval is required from either the U.S. Department of Justice or the U.S. Federal Trade Commission (FTC) under the Hart-Scott-Rodino Antitrust Improvement Act. The FTC approved the transaction on July 20, 2006, and the NCUC approved it on July 25, 2006. Application for FERC approval was filed on July 28, 2006 and is pending.

Dispositions. For the three months ended June 30, 2006, the sale of other assets and businesses resulted in approximately $8 million in proceeds and net pre-tax losses of $11 million recorded in (Losses) Gains on Sales of Other Assets and Other, net on the Consolidated Statements of Operations. For the six months ended June 30, 2006, the sale of other assets and businesses resulted in approximately $36 million in proceeds and net pre-tax gains of $22 million recorded in (Losses) Gains on Sales of Other Assets and Other, net on the Consolidated Statements of Operations. These sales exclude assets that were held for sale and reflected in discontinued operations, both of which are discussed in Note 13, and sales by Crescent Resources LLC (Crescent) which are discussed separately below. Significant sales of other assets during the six months ended June 30, 2006 are detailed as follows:

•

Natural Gas Transmission’s sale of certain Stone Mountain natural gas gathering system assets resulted in proceeds of $18 million (which is reflected in Net proceeds from the sales of equity investments and other assets, and sales of and collections on notes receivable within Cash Flows from Investing Activities in the Consolidated Statements of Cash Flows), and pre-tax gain of $5 million which was recorded in (Losses) Gains on Sales of Other Assets and Other, net in the accompanying Consolidated Statements of Operations. In addition, Natural Gas Transmission’s sale of stock, received as consideration for the settlement of a customers transportation contract, resulted in proceeds of approximately $24 million (which is reflected in Other, assets within Cash Flows from Operating Activities in the Consolidated Statements of Cash Flows) and a pre-tax gain of $24 million, of which approximately $23 million was recorded in (Losses) Gains on Sales of Other Assets and Other, net and approximately $1 million was recorded in Other Income and Expenses, net in the accompanying Consolidated Statements of Operations (see Note 10).

For the three months ended June 30, 2006, Crescent commercial and multi-family real estate sales resulted in $165 million of proceeds and $145 million of net pre-tax gains recorded in Gains on Sales of Investments in Commercial and Multi-Family Real Estate on the Consolidated Statements of Operations. For the six months ended June 30, 2006, Crescent commercial and multi-family real estate sales resulted in $221 million of proceeds and $171 million of net pre-tax gains recorded in Gains on Sales of Investments in Commercial and Multi-Family Real Estate on the Consolidated Statements of Operations. Sales primarily consisted of two office buildings at Potomac Yard

PART I

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

in Washington, D.C. for a pre-tax gain of $81 million and land at Lake Keowee in northwestern South Carolina for a pre-tax gain of $52 million, as well as several other large land tract sales.

For the three months ended June 30, 2005, the sale of other assets, businesses and equity investments resulted in approximately $13 million in proceeds, and pre-tax gains of $6 million recorded in (Losses) Gains on Sales and Impairments of Equity Investments on the Consolidated Statements of Operations. For the six months ended June 30, 2005, the sale of other assets, businesses and equity investments resulted in approximately $1.2 billion in proceeds, net pre-tax gains of $9 million recorded in (Losses) Gains on Sales of Other Assets and Other, net and pre-tax gains of $1.2 billion recorded in (Losses) Gains on Sales and Impairments of Equity Investments on the Consolidated Statements of Operations. These sales exclude assets held for sale as of June 30, 2005 and reflected in discontinued operations, both of which are discussed in Note 13, and sales by Crescent which are discussed separately below. Significant sales of other assets and equity investments during the six months ended June 30, 2005 are detailed as follows:

•

In February 2005, DEFS sold its wholly-owned subsidiary Texas Eastern Products Pipeline Company, LLC (TEPPCO GP), which is the general partner of TEPPCO Partners, LP (TEPPCO LP), for approximately $1.1 billion and Duke Energy sold its limited partner interest in TEPPCO LP for approximately $100 million, in each case to Enterprise GP Holdings LP, an unrelated third party. These transactions resulted in pre-tax gains of $1.2 billion, which have been classified as (Losses) Gains on Sales of Other Assets and Other, Net in the Consolidated Statement of Operations for the six months ended June 30, 2005. Minority Interest Expense of $343 million was recorded in the Consolidated Statement of Operations for the six months ended June 30, 2005 to reflect ConocoPhillips’ proportionate share in the pre-tax gain on sale of the TEPPCO GP.

•

Additional asset and business sales during the six month period ended June 30, 2005 total approximately $20 million in proceeds. These sales resulted in net pre-tax gains of $9 million which were recorded in (Losses) Gains on Sales of Other Assets and Other, net in the Consolidated Statements of Operations.

For the three months ended June 30, 2005, Crescent’s commercial and multi-family real estate sales resulted in $26 million of proceeds and $12 million of net pre-tax gains recorded in Gains on Sales of Investments in Commercial and Multi-Family Real Estate on the Consolidated Statements of Operations. For the six months ended June 30, 2005, Crescent’s commercial and multi-family real estate sales resulted in $77 million of proceeds and $54 million of net pre-tax gains recorded in Gains on Sales of Investments in Commercial and Multi-Family Real Estate on the Consolidated Statements of Operations. Sales consisted of several “legacy” land sales.

3. Earnings Per Common Share (EPS)

Basic EPS is computed by dividing earnings available for common stockholders by the weighted-average number of common shares outstanding during the period. Diluted EPS is computed by dividing earnings available for common stockholders, as adjusted, by the diluted weighted-average number of common shares outstanding during the period. Diluted EPS reflect the potential dilution that could occur if securities or other agreements to issue common stock, such as stock options, stock-based performance unit awards, contingently convertible debt and phantom stock awards, were exercised, settled or converted into common stock.

PART I

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

The following table illustrates Duke Energy’s basic and diluted EPS calculations and reconciles the weighted-average number of common shares outstanding to the diluted weighted-average number of common shares outstanding for the three and six months ended June 30, 2006 and 2005.


	Income			Average Shares	EPS
	(in millions, except per-share data)
Three Months Ended June 30, 2006
Income from continuing operations	$	435
Less: Dividends and premiums on redemption of preferred and preference stock		—

Income from continuing operations—basic	$	435		1,238	$	0.35

Effect of dilutive securities:
Stock options, phantom, performance and unvested stock				4
Contingently convertible bond		1		17

Income from continuing operations—diluted	$	436		1,259	$	0.34

Three Months Ended June 30, 2005
Income from continuing operations	$	328
Less: Dividends and premiums on redemption of preferred and preference stock		(2	)

Income from continuing operations—basic	$	326		927	$	0.35

Effect of dilutive securities:
Stock options, phantom, performance and unvested stock, and common stock derivatives				4
Contingently convertible bond		2		33

Income from continuing operations—diluted	$	328		964	$	0.34

Six Months Ended June 30, 2006
Income from continuing operations	$	921
Less: Dividends and premiums on redemption of preferred and preference stock		—

Income from continuing operations—basic	$	921		1,083	$	0.85

Effect of dilutive securities:
Stock options, phantom, performance and unvested stock				4
Contingently convertible bond		3		24

Income from continuing operations—diluted	$	924		1,111	$	0.83

Six Months Ended June 30, 2005
Income from continuing operations	$	1,188
Less: Dividends and premiums on redemption of preferred and preference stock		(4	)

Income from continuing operations—basic	$	1,184		941	$	1.26

Effect of dilutive securities:
Stock options, phantom, performance and unvested stock, and common stock derivatives				3
Contingently convertible bond		4		33

Income from continuing operations—diluted	$	1,188		977	$	1.21

The increase in weighted-average shares outstanding for the three and six months ended June 30, 2006 compared to the same periods in 2005 was due primarily to the April 2006 issuance of approximately 313 million shares in conjunction with the merger with Cinergy (see Note 2), the conversion of debt into approximately 26 million shares of Duke Energy common stock during the second quarter of 2006 (see Note 4), and the repurchase and retirement of approximately 17.5 million shares of Duke Energy common stock during the six months ended June 30, 2006, of which 2.4 million shares were repurchased in the first quarter of 2006 and 15.1 million shares were repurchased in the second quarter of 2006 (see Note 4).

PART I

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

Options, unvested stock, performance and phantom stock awards related to approximately 20 million shares as of June 30, 2006 and 18 million shares as of June 30, 2005 were not included in the “effect of dilutive securities” in the above table because either the option exercise prices were greater than the average market price of the common shares during those periods, or performance measures related to the awards had not yet been met.

4. Common Stock

In February 2005, Duke Energy announced plans to execute up to approximately $2.5 billion in common stock repurchases over a three year period. In May 2005, Duke Energy suspended additional repurchases, pending further assessment. At the time of suspension, Duke Energy had repurchased approximately $933 million of common stock. In the first quarter of 2006, as a result of the March 10, 2006 shareholder approval of the merger, Duke Energy’s Board of Directors authorized the repurchase of up to an additional $1 billion of common stock under the previously announced share repurchase plan. During the three and six months ended June 30, 2006, Duke Energy repurchased 15.1 million and 17.5 million shares, respectively, for total consideration of approximately $430 million and $500 million, respectively. The repurchases and corresponding commissions and other fees were recorded in Common Stockholder’s Equity as a reduction in Common Stock and Additional Paid-in Capital. In June 2006, Duke Energy suspended additional repurchases of Duke Energy common stock under the repurchase plan (see “Executive Overview” section of “Item 2. Management’s Discussion and Analysis of Results of Operations and Financial Condition.”)

On March 18, 2005, Duke Energy entered into an accelerated share repurchase transaction whereby Duke Energy repurchased and retired 30 million shares of its common stock from an investment bank at the March 18, 2005 closing price of $27.46 per share. Additionally, Duke Energy entered into a separate open-market purchase plan on March 18, 2005 to repurchase up to an additional 20 million shares of its common stock, of which approximately 2.6 million shares were repurchased prior to the May 2005 suspension of the program at a weighted average price of $28.97 per share. Total consideration paid to repurchase the shares of approximately $909 million, including commissions and other fees, was recorded in Common Stockholders’ Equity as a reduction in Common Stock and Additional Paid-in Capital.

In April 2006, Duke Energy’s $742 million of convertible debt became convertible into approximately 31.7 million shares of Duke Energy common stock due to the market price of Duke Energy common stock achieving a specified threshold. Holders of the convertible debt were able to exercise their right to convert on or prior to June 30, 2006. During the conversion period, approximately $611 million of debt was converted into approximately 26 million shares of Duke Energy common stock. At June 30, 2006, the balance of the convertible debt is approximately $131 million and remains convertible in the third quarter of 2006 into approximately 5.6 million shares of Duke Energy common stock.

See Note 2 for discussion of common stock issued in April 2006 as a result of the merger with Cinergy.

Effective in the third quarter 2006, the Board of Directors of Duke Energy has approved a quarterly dividend increase of $0.01 per share, increasing the annual dividend to $1.28 per share.

As of June 30, 2006 and December 31, 2005, approximately $402 million and $0, respectively, of dividends payable were included in Other within Current Liabilities within the Consolidated Balance Sheets. At June 30, 2006, this balance exceeded 5% of total current liabilities.

5. Stock-Based Compensation

Effective January 1, 2006, Duke Energy adopted the provisions of SFAS No. 123(R), “Share-Based Payment” (SFAS No. 123(R)). SFAS No. 123(R) establishes accounting for stock-based awards exchanged for employee and certain nonemployee services. Accordingly, for employee awards, equity classified stock-based compensation cost is measured at the grant date, based on the fair value of the award, and is recognized as expense over the requisite service period. Duke Energy previously applied Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees,” and FIN 44, “Accounting for Certain Transactions Involving Stock Compensation (an Interpretation of APB Opinion 25)” and provided the required pro forma disclosures of SFAS No. 123, “Accounting for Stock-Based Compensation” (SFAS No. 123). Since the exercise price for all options granted under those plans was equal to the market value of the underlying common stock on the grant date, no compensation cost was recognized in the accompanying Consolidated Statements of Operations.

Compensation expense for awards with graded vesting provisions is recognized in accordance with FIN 28, “Accounting for Stock Appreciation Rights and Other Variable Stock Option or Award Plans.” Duke Energy elected to adopt the modified prospective application

PART I

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

method as provided by SFAS No. 123(R), and accordingly, financial statement amounts from the prior periods presented in this Form 10-Q have not been restated. There were no modifications to outstanding stock options prior to the adoption of SFAS 123(R).

Duke Energy recorded stock-based compensation expense for the three and six months ended June 30, 2006 and 2005 as follows, the components of which are further described below:


	Three Months Ended June 30				Six Months Ended June 30
	2006		2005		2006		2005
	(in millions)
Stock Options	$	3	$	—	$	5	$	—
Stock Appreciation Rights		—		1		1		1
Phantom Stock		16		6		20		10
Performance Awards		7		7		12		14
Other Stock Awards		1		—		1		1

Total	$	27	$	14	$	39	$	26

The tax benefit associated with the recorded expense for the six months ended June 30, 2006 and 2005 was approximately $15 million and $10 million, respectively. There were no material differences in income from continuing operations, income from income taxes, net income, cash flows, or basic and diluted earnings per share from the adoption of SFAS No. 123(R).

The following table shows what earnings available for common stockholders, basic earnings per share and diluted earnings per share would have been if Duke Energy had applied the fair value recognition provisions of SFAS No. 123 to all stock-based compensation awards during prior periods.

Pro Forma Stock-Based Compensation


	Three months ended June 30, 2005			Six months ended June 30, 2005
	(in millions, except per share amounts)
Earnings available for common stockholders, as reported	$	307		$	1,173

Add: stock-based compensation expense included in reported net income, net of related tax effects		9			16
Deduct: total stock-based compensation expense determined under fair value-based method for all awards, net of related tax effects		(9	)		(16	)

Pro forma earnings available for common stockholders, net of related tax effects	$	307		$	1,173

Earnings per share
Basic—as reported	$	0.33		$	1.25
Basic—pro forma	$	0.33		$	1.25
Diluted—as reported	$	0.32		$	1.20
Diluted—pro forma	$	0.32		$	1.20

Duke Energy’s 1998 Long-term Incentive Plan, as amended (the 1998 Plan), reserved 60 million shares of common stock for awards to employees and outside directors. Under the 1998 Plan, the exercise price of each option granted cannot be less than the market price of Duke Energy’s common stock on the date of grant and the maximum option term is 10 years. The vesting periods range from immediate to five years. Duke Energy issues new shares upon exercising or vesting of share-based awards.

Upon the acquisition of Westcoast, Duke Energy converted all stock options outstanding under the 1989 Westcoast Long-term Incentive Share Option Plan to Duke Energy stock options. Certain of these options also provide for share appreciation rights under which the holder of a stock option may, in lieu of exercising the option, exercise the share appreciation right. The exercise price of these options equals the market price on the date of grant and the maximum option term is 10 years. The vesting periods range from immediate to four years.

PART I

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

Upon the acquisition of Cinergy, Duke Energy converted all stock options outstanding under the Cinergy Long-Term Incentive Plan to Duke Energy stock options. The exercise price of these options equaled the market price on the date of grant and the maximum option term is 10 years. The vesting periods are generally three years.

Stock Option Activity


	Options (in thousands)		Weighted-Average Exercise Price		Weighted-Average Remaining Life (in years)	Aggregate Intrinsic Value (in millions)
Outstanding at December 31, 2005	25,506		$	29
Granted ^(a)	9,155			24
Exercised	(2,061	)		21
Forfeited or expired	(706	)		30

Outstanding at June 30, 2006	31,894			29	5.2	$	131

Exercisable at June 30, 2006	26,908		$	30	4.6		96

(a)	Includes 7,277,522 converted Cinergy stock options

On December 31, 2005, Duke Energy had 22 million exercisable options with a $32 weighted-average exercise price. The total intrinsic value of options exercised during the six months ended June 30, 2006 and 2005 was approximately $17 million and $13 million, respectively. Cash received from options exercised during the six months ended June 30, 2006 was approximately $42 million, with a related tax benefit of approximately $6 million.

In addition to the conversion of the Cinergy stock options noted above, Duke Energy granted 1,877,646 options (fair value of approximately $10 million based on a Black-Scholes model valuation) during the six months ended June 30, 2006. There were no options grants during the year ended December 31, 2005. Remaining compensation expense to be recognized for unvested converted Cinergy options was determined using a Black-Scholes model.

Weighted-Average Assumptions for Option Pricing


		2006
Risk-free interest rate ⁽¹⁾		4.78%
Expected dividend yield ⁽²⁾		4.40%
Expected life ⁽³⁾		6.29 yrs.
Expected volatility ⁽⁴⁾		24%

(1)	The risk free rate is based upon the U.S. Treasury Constant Maturity rates as of the grant date.

(2)	The expected dividend yield is based upon annualized dividends and the 1-year average closing stock price,

(3)	The expected term of options is derived from historical data.

(4)

Volatility is based upon 50% historical and 50% implied volatility. Historic volatility is based on the weighted average between Duke and Cinergy historical volatility over the expected life using daily stock prices. Implied volatility is the average for all option contracts with a term greater than six months using the strike price closest to the stock price on the valuation date.

The 1998 Plan allows for a maximum of twelve million shares of common stock to be issued under various stock-based awards. Payments for cash settled awards during the period were immaterial.

Stock-based performance awards outstanding under the 1998 Plan generally vest over three years. Vesting for certain stock-based performance awards can occur in three years, at the earliest, if performance is met. Certain performance awards granted in 2006 contain market conditions based on the total shareholder return (TSR) of Duke Energy stock (relative TSR). These awards are valued using a path-dependent model that incorporates expected relative TSR into the fair value determination of Duke Energy’s performance-based share awards with the adoption of SFAS No. 123(R). The model uses three year historical volatilities and correlations for all companies in the pre-defined peer group, including Duke Energy, to simulate Duke Energy’s relative TSR as of the end of the performance period. For each simulation, Duke Energy’s relative TSR associated with the simulated stock price at the end of the performance period plus expected dividends within the period results in a value per share for the award portfolio. The average of these simulations is the expected portfolio value per share. Actual life to date results of Duke Energy’s relative TSR for each grant is incorporated within the model. Other awards not containing market conditions are measured at grant date price. Duke Energy awarded 1,531,700 shares (fair value of approximately $31 million) in the six months ended June 30, 2006, and 1,273,830 shares (fair value of approximately $34 million, based on the market price of Duke Energy’s common stock at the grant date) in the six months ended June 30, 2005.

PART I

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

The following table summarizes information about stock-based performance awards outstanding at June 30, 2006:


	Shares		Weighted Average Grant Date Fair Value
Number of Stock-based Performance Awards:
Outstanding at December 31, 2005	2,940,768		$	25
Granted	1,531,700			20
Vested	(114,000	)		27
Forfeited	(206,213	)		26
Canceled	—			—

Outstanding at June 30, 2006	4,152,255			23

The total fair value of the shares vested during the six months ended June 30, 2006 and 2005 was approximately $3 million. As of June 30, 2006, Duke Energy had approximately $46 million of compensation expense which is expected to be recognized over a weighted-average period of 1.5 years.

Phantom stock awards outstanding under the 1998 Plan generally vest over periods from immediate to five years. Duke Energy awarded 1,096,580 shares (fair value of approximately $32 million) based on the market price of Duke Energy’s common stock at the grant dates in the six months ended June 30, 2006, and 1,138,930 shares (fair value of approximately $31 million) in the six months ended June 30, 2005. Converted Cinergy phantom stock awards are paid in cash and are measured and recorded as liability awards.

The following table summarizes information about phantom stock awards outstanding at June 30, 2006:


	Shares		Weighted Average Grant Date Fair Value
Number of Phantom Stock Awards:
Outstanding at December 31, 2005	2,517,020		$	25
Granted ^(b)	1,128,110			29
Vested	(592,618	)		25
Forfeited	(135,103	)		26
Canceled	—			—

Outstanding at June 30, 2006	2,917,409			27

(b)	Includes 31,530 converted Cinergy awards

The total fair value of the shares vested during the six months ended June 30, 2006 and 2005 was approximately $15 million and $7 million, respectively. As of June 30, 2006, Duke Energy had approximately $38 million of compensation expense which is expected to be recognized over a weighted-average period of 3.2 years.

Other stock awards outstanding under the 1998 Plan generally vest over periods from three to five years. Duke Energy awarded 279,000 shares (fair value of approximately $8 million) based on the market price of Duke Energy’s common stock at the grant dates in the six months ended June 30, 2006, and 35,000 shares (fair value of approximately $1 million) in the six months ended June 30, 2005.

The following table summarizes information about other stock awards outstanding at June 30, 2006:


	Shares		Weighted Average Grant Date Fair Value
Number of Other Stock Awards:
Outstanding at December 31, 2005	178,337		$	25
Granted ^(c)	329,980			28
Vested	(69,610	)		26
Forfeited	—			—
Canceled	—			—

Outstanding at June 30, 2006	438,707			27

(c)	Includes 50,980 converted Cinergy awards

PART I

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

The total fair value of the shares vested during the six months ended June 30, 2006 and 2005 was approximately $2 million and $1 million, respectively. As of June 30, 2006, Duke Energy had approximately $10 million of compensation expense which is expected to be recognized over a weighted-average period of 3.3 years.

6. Inventory

Inventory is recorded at the lower of cost or market value, primarily using the average cost method. The increase in inventory at June 30, 2006 as compared to December 31, 2005 is primarily attributable to inventory acquired as part of the merger with Cinergy.

Inventory


	June 30, 2006		December 31, 2005
	(in millions)
Materials and supplies	$	583	$	434
Natural gas		218		269
Coal held for electric generation		356		115
Petroleum products		44		45

Total inventory	$	1,201	$	863

7. Debt and Credit Facilities

As discussed in Note 4, in April 2006, Duke Energy’s $742 million of convertible debt became convertible into approximately 31.7 million shares of Duke Energy common stock due to the market price of Duke Energy common stock achieving a specified threshold. During the conversion period, approximately $611 million of debt was converted into approximately 26 million shares of Duke Energy Common Stock.

Duke Energy’s debt balance increased at June 30, 2006 as compared to December 31, 2005 primarily as a result of the merger with Cinergy (see Note 2).

In June 2006, PSI issued $325 million principal amount of 6.05% senior unsecured notes due June 15, 2016. Proceeds from the issuance were used to repay $325 million of 6.65% First Mortgage Bonds that matured on June 15, 2006.

In August 2006, ULH&P issued approximately $77 million principal amount of floating rate tax-exempt notes due August 1, 2027. Proceeds from the issuance will be used to refund a like amount of debt on September 1, 2006 currently outstanding at CG&E. Approximately $27 million of the floating rate debt was swapped to a fixed rate concurrent with closing.

Available Credit Facilities and Restrictive Debt Covenants. In the second quarter of 2006, Duke Energy closed on the syndication of $3.1 billion in revolving credit facilities in the U.S. and 600 million in Canadian dollars. These syndications, which were amendments to and extensions of existing U.S. and Canadian credit facilities, extended the terms of the credit facilities by one year and built in covenant flexibility where appropriate to allow Duke Energy to pursue certain strategic activities, including the separation of the gas and electric businesses. Additionally, terms for the Cinergy’s facilities were conformed to less restrictive Duke covenants.

During the six months ended June 30, 2006, Duke Energy’s consolidated credit capacity increased by approximately $764 million, primarily due to the merger with Cinergy. This increase was net of other reductions in credit capacity due to the terminations of an $800 million syndicated credit facility and $460 million in bi-lateral credit facilities. The terminations of these credit facilities primarily reflect Duke Energy’s reduced liquidity needs as a result of exiting the DENA business (see Note 13).

The issuance of commercial paper, letters of credit and other borrowings reduces the amount available under the available credit facilities.

Duke Energy’s debt and credit agreements contain various financial and other covenants. Failure to meet those covenants beyond applicable grace periods could result in accelerated due dates and/or termination of the agreements. As of June 30, 2006, Duke Energy was in compliance with those covenants. In addition, credit agreements allow for acceleration of payments or termination of the agreements due to nonpayment, or in some cases, due to the acceleration of other significant indebtedness of the borrower or some of its subsidiaries. None of the debt or credit agreements contain material adverse change clauses.

PART I

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

As of June 30, 2006, approximately $323 million of Cinergy Pollution Control notes were classified in Notes Payable and Commercial Paper in the Consolidated Balance Sheets.

Credit Facilities Summary as of June 30, 2006 (in millions)


				Amounts Outstanding
	Expiration Date	Credit Facilities Capacity		Commercial Paper		Letters of Credit		Total
Duke Power Company LLC
$500 multi-year syndicated ^{(a), (b), (c)}	June 2011
$150 364-day bi-lateral ^{(a), (b)}	September 2006
Total Duke Power Company LLC		$	650	$	300	$	—	$	300
Duke Capital LLC
$600 multi-year syndicated ^{(a), (b), (d)}	June 2010
$130 three-year bi-lateral ^(b)	October 2007
$120 multi-year bi-lateral ^(b)	July 2009
Total Duke Capital LLC			850		—		372		372
Westcoast Energy Inc.
$180 multi-year syndicated ^{(c), (e)}	June 2011		180		—		—		—
Union Gas Limited
$360 364-day syndicated ^(f)	June 2007		360		—		—		—
Cinergy Corp.
$2,000 multi-year syndicated ^{(a), (b), (g)}	June 2011		2,000		949		93		1,042

Total ^(h)		$	4,040	$	1,249	$	465	$	1,714

(a)	Credit facility contains an option allowing borrowing up to the full amount of the facility on the day of initial expiration for up to one year.

(b)	Credit facility contains a covenant requiring the debt-to-total capitalization ratio to not exceed 65%.

(c)	In June 2006, credit facility expiration date was extended from June 2010 to June 2011.

(d)	In June 2006, credit facility expiration date was extended from June 2009 to June 2010.

(e)	Credit facility is denominated in Canadian dollars totaling 200 million Canadian dollars and contains a covenant that requires the debt-to-total capitalization ratio to not exceed 75%.

(f)

In June 2006, credit facility was amended to increase the amount from 300 to 400 million Canadian dollars, in addition to extending the maturity from June 2006 to June 2007. It contains a covenant requiring the debt-to-total capitalization ratio to not exceed 75% and an option at maturity allowing for the conversion of all outstanding loans to a term loan repayable up to one year after maturity date but not exceeding 18 months from the date of draw.

(g)	Contains $500 million sub limits each for CG&E and PSI. In June 2006, the credit facility expiration date was extended from September 2010 to June 2011.

(h)	Various credit facilities that support ongoing or discontinued operations and miscellaneous transactions are not included in this credit facilities summary.

PART I

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

8. Employee Benefit Obligations

The following tables show the components of the net periodic pension costs (income) for Duke Energy’ U.S. retirement plans and Westcoast Energy, Inc. (Westcoast) Canadian retirement plans. Net periodic pension costs of Cinergy are included in the below tables for the period from the date of acquisition and thereafter.


Components of Net Periodic Pension Costs: Qualified Pension Benefits (Income)

	Three Months Ended June 30,						Six Months Ended June 30,
	2006			2005			2006			2005
	(in millions)
Duke Energy U.S.
Service cost	$	30		$	16		$	47		$	31
Interest cost on projected benefit obligation		66			40			104			79
Expected return on plan assets		(81	)		(57	)		(137	)		(114	)
Amortization of prior service cost		—			(1	)		(1	)		(1	)
Amortization of loss		13			8			27			17

Net periodic pension costs	$	28		$	6		$	40		$	12

Westcoast
Service cost	$	3		$	2		$	6		$	4
Interest cost on projected benefit obligation		8			8			16			15
Expected return on plan assets		(8	)		(7	)		(16	)		(13	)
Amortization of loss		3			1			5			2

Net periodic pension costs	$	6		$	4		$	11		$	8


Components of Net Periodic Pension Costs: Non-Qualified Pension Benefits

	Three Months Ended June 30,						Six Months Ended June 30,
	2006			2005			2006			2005
	(in millions)
Duke Energy U.S.
Service cost	$	1		$	—		$	2		$	—
Interest cost on projected benefit obligation		2			1			3			2
Amortization of prior service cost		1			1			1			1
Amortization of net transition asset		—			—			—			1

Net periodic pension costs	$	4		$	2		$	6		$	4

Westcoast
Service cost	$	—		$	—		$	—		$	—
Interest cost on projected benefit obligation		1			1			2			2
Amortization of loss		—			—			1			—

Net periodic pension costs	$	1		$	1		$	3		$	2

Duke Energy’s policy is to fund amounts for U.S. retirement plans on an actuarial basis to provide sufficient assets to meet benefit payments to plan participants. Duke Energy has not made contributions to its U.S. retirement plan for the three and six month ended June 30, 2006. Duke Energy expects to make contributions of approximately $120 million to the legacy Cinergy qualified pension plans during the remainder of 2006.

PART I

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

Westcoast’s policy is to fund its defined benefit (DB) retirement plans on an actuarial basis and in accordance with Canadian pension standards legislation, in order to accumulate assets sufficient to meet benefit payments. Contributions to the defined contribution (DC) retirement plans are determined in accordance with the terms of the plans. Duke Energy has contributed $11 million to the Westcoast DB plans for the three month period ended June 30, 2006 and $21 million for the six months ended June 30, 2006. Duke Energy anticipates that it will make total contributions of approximately $42 million in 2006. Duke Energy has contributed $1 million to the Westcoast DC plans for the three months ended June 30, 2006 and $2 million for the six months ended June 30, 2006, and anticipates that it will make total contributions of approximately $4 million in 2006. Duke Energy has contributed $1 million to the Westcoast non-qualified plans for the three months ended June 30, 2006 and $2 million for the six months ended June 30, 2006, and anticipates that it will make total contributions of approximately $4 million in 2006.

The following table shows the components of the net periodic post-retirement benefit costs for the Duke Energy U.S. other post-retirement benefit plans and the Westcoast other post-retirement benefit plans.

Components of Net Periodic Post-Retirement Benefit Costs (Income)


	Three Months Ended June 30,						Six Months Ended June 30,
	2006			2005			2006			2005
	(in millions)
Duke Energy U.S.
Service cost benefit	$	4		$	2		$	6		$	3
Interest cost on accumulated post—retirement benefit obligation		17			12			28			23
Expected return on plan assets		(4	)		(5	)		(8	)		(9	)
Amortization of net transition liability		4			4			8			8
Amortization of loss		3			2			5			4

Net periodic post-retirement benefit costs	$	24		$	15		$	39		$	29

Westcoast
Service cost benefit	$	1		$	—		$	2		$	1
Interest cost on accumulated post—retirement benefit obligation		2			1			3			2
Amortization of loss		—			1			1			1

Net periodic post-retirement benefit costs	$	3		$	2		$	6		$	4

Duke Energy also sponsors employee savings plans that cover substantially all U.S. employees. Duke Energy expensed employer matching contributions of $17 million for the three months ended June 30, 2006 compared to $14 million for the three months ended June 30, 2005. Duke Energy expensed employer matching contributions of approximately $41 million for the six months ended June 30, 2006 compared to $34 million for the six months ended June 30, 2005.

PART I

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

9. Goodwill and Intangibles

Duke Energy evaluates the impairment of goodwill under the guidance of SFAS No. 142, “Goodwill and Other Intangible Assets.” As discussed further in Note 2, in April 2006, Duke Energy and Cinergy consummated the previously announced merger, which resulted in Duke Energy recording goodwill and intangible assets of approximately $5.4 billion. The following table shows the components of goodwill at June 30, 2006:

Changes in the Carrying Amount of Goodwill


	Balance December 31, 2005		Acquisitions ^(a)		Other ^(b)			Balance June 30, 2006
	(in millions)
Natural Gas Transmission	$	3,512	$	—	$	128		$	3,640
International Energy		256		—		11			267
Crescent		7		—		—			7
Unallocated ^(a)		—		4,289		(161	)		4,128

Total consolidated	$	3,775	$	4,289	$	(22	)	$	8,042

(a)

Goodwill recorded as of June 30, 2006 resulting from Duke Energy’s merger with Cinergy is $4,289 million. The valuation and other assessment procedures required to allocate this goodwill to the appropriate reporting units and reportable segments is currently in process and is anticipated to be completed by the end of 2006. While the allocation is not yet complete, Duke Energy anticipates that the goodwill will be allocated to the U.S. Franchised Electric and Gas and Commercial Power segments, as well as Other, with at least half of the goodwill likely relating to the U.S. Franchised Electric and Gas segment.

(b)	Primarily relates to foreign currency translation and goodwill allocated to the distribution of Cinergy Marketing and Trading, LP, and Cinergy Canada, Inc. (see Note 13)

Intangible Assets

Intangible assets acquired via merger with Cinergy. In connection with the merger with Cinergy, Duke Energy recorded intangible assets of approximately $1,092 million, primarily relating to approximately $710 million of emission allowances and approximately $370 million of gas, coal and power contracts. Additionally, Duke Energy recorded liabilities associated with other power sale contracts amounting to approximately $66 million.

The carrying amount and accumulated amortization of intangible assets as of June 30, 2006 and December 31, 2005 are as follows:


	June 30, 2006			December 31, 2005			Weighted Average Life
				(in millions)
Emission allowances	$	703		$	24		^(a	⁾
Gas, coal and power contracts		320			23		^(b	⁾
Other		57			23		30

Total gross carrying amount		1,080			70

Accumulated amortization—gas, coal and power contracts		(18	)		(1	)
Accumulated amortization—other		(14	)		(4	)

Total accumulated amortization		(32	)		(5	)

Total intangible assets, net	$	1,048		$	65

(a)	Emission allowances do not have a contractual term or expiration date.

(b)	Of this balance, approximately $115 million will be amortized as consumed and does not have a definitive life, and approximately $155 million will be amortized on a straight line basis over 20 years.

PART I

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

Emission allowances, which do not have an expiration date, will be recognized in earnings as they are consumed or sold. Gains or losses on sales of emission allowances are presented on a net basis in Gain (Loss) on Sales of Other Assets and Other, net in the accompanying Consolidated Statements of Operations. The estimated recognition of the acquired value of emission allowances is currently anticipated to be approximately $200 million during the remainder of 2006, $147 million in 2007, $94 million in 2008, $84 million in 2009, $32 million in 2010 and $46 million in 2011. Approximately $115 million of the step-ups in value of gas, coal and power contracts will primarily be recognized in earnings on a consumption basis and are estimated to amount to $20 million for the remainder of 2006, $44 million in 2007, $17 million in 2008, $17 million in 2009, $12 million in 2010 and $5 million in 2011. Approximately $155 million of the step-ups in the value of gas, coal and power contracts relates to a long-term power contract to buy power from a generating company of which Duke Energy owns 9%. The value of this contract will be amortized on a straight-line basis over the current contractual period, which runs through March 2026. Amortization expense for this contract will amount to approximately $5 million for the remainder of 2006 and approximately $8 million in the years 2007 through 2010. Amortization expense for all other intangible assets is estimated to amount to approximately $4 million for the remainder of 2006, $3 million for each of the years 2007 through 2010 and approximately $2 million in 2011.

Additionally, Duke Energy recorded liabilities associated with a rate stabilization plan (RSP) in Ohio that will be recognized in earnings over the remaining regulatory period, which ends on December 31, 2008. Amortization expense related to the RSP is estimated to amount to approximately $4 million for the remainder of 2006, $44 million in 2007 and $67 million in 2008. The liability amounts allocated to other power sale contracts will be amortized to income as follows: $10 million during the remainder of 2006, $17 million in 2007, and approximately $5 million in each of the years 2008 through 2011.

The amortization amounts discussed above are estimates. Actual amounts may differ from these estimates due to such factors as changes in consumption patterns, sales or impairments of emission allowances or other intangible assets, additional intangible acquisitions and other events.

Emission allowances sold or consumed during the three and six months ended June 30, 2006 was $87 million and $95 million, respectively. Emission allowances sold or consumed during the three and six months ended June 30, 2005 was immaterial. Amortization expense for intangible assets for the three months ended June 30, 2006 and 2005 was $6 million and $1 million, respectively. Amortization expense for intangible assets for the six months ended June 30, 2006 and 2005 was approximately $8 million and $1 million, respectively.

10. Marketable Securities

During the six months ended June 30, 2006, Duke Energy’s Natural Gas Transmission business unit received shares of stock as consideration for settlement of a customer’s transportation contract. The market value of the equity securities, determined by quoted market prices on the date of receipt, of approximately $23 million is reflected in (Losses) Gains on Sales of Other Assets and Other, net in the Consolidated Statements of Operations for the six months ended June 30, 2006. Subsequent to receipt, these securities were accounted for under SFAS No. 115, “ Accounting for Certain Investments in Debt and Equity Securities ,” as trading securities. During the six months ended June 30, 2006, these securities were sold and an additional gain of approximately $1 million was recognized in Other Income and Expenses, net in the Consolidated Statements of Operations for the six months ended June 30, 2006.

11. Severance

During the three months ended June 30, 2006, Duke Energy accrued approximately $55 million related to voluntary and involuntary severance as a result of the merger with Cinergy (see Note 2). Additionally, Duke Energy recorded approximately $38 million in severance liabilities related to legacy Cinergy that was included in goodwill at the merger date. Duke Energy does not anticipate any additional material severance liabilities as a result of the merger and payments under existing agreements will occur as the service periods expire. All remaining payments related to this severance program are expected to be made by the end of 2006.

As discussed in Note 13, in June 2006, Duke Energy announced it had reached an agreement to sell Cinergy Marketing and Trading, LP, and Cinergy Canada, Inc., as well as associated contracts managed by these companies, to Fortis, a Benelux-based financial services group. As such, results of operations for Cinergy Marketing and Trading, LP (CMT), and Cinergy Canada, Inc., have been reflected in Loss from Discontinued Operations, net of tax, from the date of the Cinergy acquisition to June 30, 2006. Duke Energy does not currently anticipate recording material severance liabilities as a result of the disposal of CMT.

PART I

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

As discussed further in Note 13, during the third quarter of 2005, the Board of Directors of Duke Energy authorized and directed management to execute the sale or disposition of substantially all of DENA’s remaining assets and contracts outside the Midwestern United States and certain contractual positions related to the Midwestern assets. As a result of this exit plan, DENA anticipates involuntary termination of approximately 250 employees by the end of the third quarter of 2006. Management anticipates future severance costs related to this exit plan not included in the following table will be immaterial.

Severance Reserve


	Balance at January 1, 2006		Provision/ Adjustments			Cash Reductions			Balance at June 30, 2006
	(in millions)
U.S. Franchised Electric and Gas	$	—	$	2		$	—		$	2
Natural Gas Transmission		3		(1	)		—			2
Other ^(a) ^(b)		28		94			(58	)		64

Total ^(c)	$	31	$	95		$	(58	)	$	68

(a)	Of the $95 million in the provision/adjustments column for the second quarter of 2006, approximately $67 million was recorded as a charge to income, approximately $38 million was recorded in goodwill and approximately $1 million was deferred as a regulatory asset.

(b)	Amounts associated with DENA’s discontinued operations are included as part of Other (see Note 13).

(c)	Substantially all remaining severance payments are expected to be applied to the reserves within one year from the date that the provision was recorded.

12. Impairments and Other Charges

International Energy. During the three months ended June 30, 2006, International Energy recorded a $55 million other-than-temporary impairment charge related to an investment in Compañía de Servicios de Compresión de Campeche, S.A. de C.V. (Campeche), a natural gas compression facility in the Cantarell oil field in the Gulf of Mexico. Campeche project revenues are generated from the gas compression services agreement (GCSA) with the Mexican National Oil Company (PEMEX). The current GCSA expires on November 7, 2006 and there have been ongoing discussions between Campeche and PEMEX to either sell the Campeche investment or renew the GCSA. In the second quarter of 2006, based on ongoing discussions with PEMEX, it was determined that there was a limited future need for Campeche’s gas compression services. Management of International Energy determined that it is probable that the Campeche investment will ultimately be sold or the GCSA will be renewed for a significantly lower rate. An other-than-temporary impairment loss was recorded to reduce the carrying value to $14 million, which is management’s best estimate of realizable value. The charges consist of a $17 million impairment of the carrying value of the equity method investment, which has been classified within (Losses) Gains on Sales and Impairments of Equity Investments in the Consolidated Statements of Operations for the three and six months ended June 30, 2006, and a $38 million impairment of notes receivable from Campeche, which has been classified within Operations, Maintenance and Other in the Consolidated Statements of Operations for the three and six months ended June 30, 2006.

Field Services. During the six months ended June 30, 2005, the Field Services business unit recorded a charge of approximately $120 million due to the reclassification into earnings of pre-tax unrealized losses from accumulated other comprehensive income (AOCI) as a result of the discontinuance of certain cash flow hedges entered into to hedge Field Services’ commodity price risk. See Note 15 for a discussion of the impacts of the DEFS disposition transaction on certain cash flow hedges.

PART I

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

13. Discontinued Operations and Assets Held for Sale

The following table summarizes the results classified as Discontinued Operations, net of tax, in the Consolidated Statements of Operations.


			Operating Loss									Net Loss on Dispositions
	Operating Revenues		Pre-tax Operating (Loss) Gain			Income Tax (Benefit) Expense			Operating Loss, Net of Tax			Pre-tax (Loss) Gain on Dispositions			Income Tax (Benefit) Expense			(Loss) Gain on Dispositions, Net of Tax			(Loss) Gain From Discontinued Operations, Net of Tax
	(in millions)
Three Months Ended June 30, 2006
Other ^(a)	$	143	$	(44	)	$	(15	)	$	(29	)	$	(78	)	$	(28	)	$	(50	)	$	(79	)
International Energy		—		(1	)		(1	)		—			9			4			5			5
Commercial Power		2		(11	)		(3	)		(8	)		(6	)		(8	)		2			(6	)

Total consolidated	$	145	$	(56	)	$	(19	)	$	(37	)	$	(75	)	$	(32	)	$	(43	)	$	(80	)

Three Months Ended June 30, 2005
Other ^(a)	$	386	$	(27	)	$	—		$	(27	)	$	(1	)	$	(9	)	$	8		$	(19	)
International Energy		—		2			2			—			—			—			—			—
Crescent		1		—			—			—			—			—			—			—

Total consolidated	$	387	$	(25	)	$	2		$	(27	)	$	(1	)	$	(9	)	$	8		$	(19	)

Six Months Ended June 30, 2006
Other ^(a)	$	489	$	(54	)	$	(8	)	$	(46	)	$	(234	)	$	(85	)	$	(149	)	$	(195	)
International Energy		—		(1	)		(1	)		—			(10	)		(3	)		(7	)		(7	)
Commercial Power		2		(11	)		(3	)		(8	)		(6	)		(8	)		2			(6	)

Total consolidated	$	491	$	(66	)	$	(12	)	$	(54	)	$	(250	)	$	(96	)	$	(154	)	$	(208	)

Six Months Ended June 30, 2005
Field Services	$	4	$	—		$	—		$	—		$	—		$	—		$	—		$	—
Other ^(a)		877		(25	)		(13	)		(12	)		—			—			—			(12	)
International Energy		—		4			3			1			—			—			—			1
Crescent		1		—			—			—			—			—			—			—

Total consolidated	$	882	$	(21	)	$	(10	)	$	(11	)	$	—		$	—		$	—		$	(11	)

(a)	Other includes the results for Duke Energy North America’s (DENA) discontinued operations, which were previously reported in the DENA segment

The following table presents the carrying values of the major classes of assets and associated liabilities held for sale in the Consolidated Balance Sheets as of June 30, 2006 and December 31, 2005.

Summarized Balance Sheet Information for Assets and Associated Liabilities Held for Sale


	June 30, 2006		December 31, 2005
	(in millions)
Current assets	$	1,309	$	1,528
Investments and other assets		610		2,059
Property, plant and equipment, net		25		1,538

Total assets held for sale	$	1,944	$	5,125

Current liabilities	$	885	$	1,488
Long-term debt		—		61
Deferred credits and other liabilities		444		2,024

Total liabilities associated with assets held for sale	$	1,329	$	3,573

PART I

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

Other

During the third quarter of 2005, Duke Energy’s Board of Directors authorized and directed management to execute the sale or disposition of substantially all of DENA remaining assets and contracts outside the Midwestern United States and certain contractual positions related to the Midwestern assets. The DENA assets to be divested include:

•

Approximately 6,100 MW of power generation located primarily in the Western and Eastern United States, including all of the commodity contracts (primarily forward gas and power contracts) related to these facilities,

•

All remaining commodity contracts related to DENA’s Southeastern generation operations, which were substantially disposed of in 2004, and certain commodity contracts related to DENA’s Midwestern power generation facilities, and

•

Contracts related to DENA’s energy marketing and management activities, which include gas storage and transportation, structured power and other contracts.

As of the September 2005 exit announcement date, management anticipated that additional charges would be incurred related to the exit plan, including termination costs for gas transportation, storage, structured power and other contracts of approximately $600 million to $800 million, which included approximately $40 million to $60 million of severance, retention and other transaction costs (see Note 11). Approximately $700 million has been incurred from the announcement date through June 30, 2006, of which approximately $80 million and $240 million was incurred during the three and six month periods ended June 30, 2006, respectively, and was recognized in Loss From Discontinued Operations, net of tax. Management does not anticipate any additional material charges related to the DENA exit plan.

In January 2006, Duke Energy signed an agreement to sell to LS Power DENA’s entire fleet of power generation assets outside the Midwest, representing approximately 6,100 megawatts of power generation located in the Western and Northeast United States. In May 2006, the transaction with LS Power closed and total proceeds from the sale were approximately $1.56 billion, including certain working capital adjustments. Additional proceeds of up to approximately $40 million are subject to LS Power obtaining certain state regulatory approvals. Subject to the resolution of these contingencies, an additional gain on the disposition of these assets could be recognized in a future period. On July 20, 2006 the Public Utilities Commission of the State of California approved a toll arrangement related to the Moss Landing facility previously sold to LS Power. Upon successful completion of a 30 day appeals process LS Power, per the PSA, will make an additional payment to DENA of approximately $40 million. DENA will record this additional gain on sale of assets when received. This additional gain is expected to be received and recorded in Q3 2006.

As of June 30, 2006 and December 31, 2005, DENA’s assets and liabilities to be disposed of under the exit plan were classified as Assets Held for Sale in the Consolidated Balance Sheets.

The results of operations of DENA’s Western and Eastern United States generation assets, including related commodity contracts, certain contracts related to DENA’s energy marketing and management activities and certain general and administrative costs, are required to be classified as discontinued operations for current and prior periods in the accompanying Consolidated Statements of Operations. GAAP requires an ongoing assessment of the continued qualification for discontinued operations presentation for the period up through one year following disposal. While this assessment requires judgment, management is not currently aware of any matters or events that are likely to occur that would impact the presentation of these operations as discontinued operations.

DENA’s Midwestern generation assets are being retained and, therefore, the results of operations for these assets, including related commodity contracts, do not qualify for discontinued operations classification and remain in continuing operations. Additionally, DENA’s Southeastern generation operations, including related commodity contracts do not meet the requirements for discontinued operations classification due to Duke Energy’s continuing involvement with these operations. In addition, the results for Duke Energy Trading and Marketing, LLC (DETM) will continue to be reported in continuing operations until the wind down of these operations is complete.

In the first quarter of 2005, DENA’s Grays Harbor facility was sold to an affiliate of Invenergy LLC, resulting in a pre-tax gain of approximately $21 million (excluding any potential contingent consideration).

Commercial Power

In June 2006, Duke Energy announced it had reached an agreement to sell Cinergy Marketing and Trading, LP, and Cinergy Canada, Inc., as well as certain CG&E trading contracts, to Fortis, a Benelux-based financial services group. Duke Energy will receive a base purchase price of approximately $210 million. In addition, Fortis will pay an amount equal to the value of the portfolio of contracts and net

PART I

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

working capital, including collateral, associated with the business, both of which will be determined at closing and are subject to market and operating changes up until that time. Duke Energy expects pre-tax cash proceeds from the sale to be at least $550 million, including the value of the portfolio of contracts and net working capital. The sale is subject to FERC and Federal Reserve Board approval, as well as Canadian regulatory approvals, and is anticipated to close in the third quarter of 2006. Results of operations for Cinergy Marketing and Trading, LP, and Cinergy Canada, Inc., as well as certain CG&E trading contracts, have been reflected in Loss from Discontinued Operations, net of tax, from the date of the Cinergy acquisition to June 30, 2006. Duke Energy does not currently expect a material gain or loss to be recognized in connection with this transaction. As of June 30, 2006, assets and liabilities to be disposed of under the exit plan were classified as Assets Held for Sale in the Consolidated Balance Sheets.

International Energy

International Energy held a receivable from Norsk Hydro ASA (Norsk) related to the 2003 sale of International Energy’s European business. In the first quarter of 2006, based on management’s best estimate of recoverability, International Energy recorded an allowance of approximately $19 million ($12 million after tax) against this receivable, which was recorded in Loss From Discontinued Operations, net of tax on the Consolidated Statements of Operations. This allowance reduced the carrying value of the receivable to approximately $24 million at March 31, 2006. During the second quarter of 2006, International Energy and Norsk signed a settlement agreement in which Norsk agreed to pay International Energy approximately $34 million in full settlement of International Energy’s receivable. In connection with this settlement, International Energy recorded an approximate $9 million write-up ($5 million after tax) of the receivable through a reduction in the valuation allowance, which was recorded in Loss From Discontinued Operations, net of tax on the Consolidated Statements of Operations for the three months ended June 30, 2006. In July 2006, International Energy received the settlement proceeds.

14. Business Segments

In conjunction with the merger with Cinergy, effective with the second quarter ended June 30, 2006, Duke Energy has adopted new business segments that management believes properly align the various operations of the merged companies with how the chief operating decision maker views the business. Prior period segment information has been retrospectively adjusted to conform to the new segment structure. Accordingly, the Duke Energy reportable business segments are as follows:

•

U.S. Franchised Electric and Gas—consists of Duke Energy Carolinas (pre-merger Duke Energy’s Franchised Electric segment regulated electric utility business in North Carolina and South Carolina) and legacy Cinergy regulated operations (consisting of the following Cinergy subsidiaries: CG&E’S regulated transmission and distribution, PSI and ULH&P

•

Natural Gas Transmission—segment is the same as former Duke Energy business segment

•

Field Services—segment is the same as former Duke Energy business segment

•

Commercial Power—CG&E’s non-regulated generation including DENA’s Midwestern operations (pre-merger included in Other) and Duke Energy Generation Services (formerly Cinergy Solutions)

•

International Energy—consists of Duke Energy International (DEI) and Cinergy’s international equity interest in a gas distribution system

•

Crescent—segment is the same as former Duke Energy business segment

Cinergy, a Delaware corporation organized in 1993, owns all outstanding common stock of its public utility companies, CG&E and PSI, which are public utilities, as well as other businesses including (a) cogeneration and energy efficiency investments and (b) natural gas and power marketing and trading operations, conducted primarily through one of Cinergy’s subsidiaries, CMT.

CG&E, an Ohio corporation organized in 1837, is a combination electric and gas public utility company that provides service in the southwestern portion of Ohio and, through ULH&P, in nearby areas of Kentucky. CG&E’s principal lines of business include generation, transmission, and distribution of electricity, the sale of and/or transportation of natural gas, and power marketing and trading.

PSI, an Indiana corporation organized in 1942, is a vertically integrated and regulated electric utility that provides service in north central, central, and southern Indiana. Its primary line of business is generation, transmission, and distribution of electricity.

Duke Energy’s chief operating decision maker regularly reviews financial information about each of these business units in deciding how to allocate resources and evaluate performance. All of the business units are considered reportable segments under SFAS No. 131,

PART I

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

“Disclosures about Segments of an Enterprise and Related Information.” Prior to the September 2005 announcement of the exiting of the majority of DENA’s businesses, DENA’s operations were considered a separate reportable segment. There is no aggregation within Duke Energy’s defined business segments.

The remainder of Duke Energy’s operations is presented as “Other.” While it is not considered a business segment, Other primarily includes DENA’s discontinued operations, certain unallocated corporate costs, including certain costs to achieve related to the merger with Cinergy, certain discontinued hedges, DukeNet Communications, LLC, Duke Energy Merchants, LLC (DEM), DETM, Bison Insurance Company Limited (Bison), Duke Energy’s wholly-owned, captive insurance subsidiary, and Duke Energy’s 50% interest in Duke/Fluor Daniel (D/FD).

In February 2005, DEFS sold its wholly-owned subsidiary TEPPCO GP, which is the general partner of TEPPCO LP, and Duke Energy sold its limited partner interest in TEPPCO LP, in each case to Enterprise GP Holdings LP, an unrelated third party (see Note 2).

During the first quarter of 2005, Duke Energy discontinued hedge accounting for certain contracts related to Field Services’ commodity price risk and changes in the fair value of these contracts subsequent to hedge discontinuance have been classified in Other. See Note 15 for further discussion.

During the first quarter of 2005, Duke Energy recognized a charge to increase liabilities associated with mutual insurance companies of $28 million in Other, which was a correction of an immaterial accounting error related to prior periods.

Duke Energy’s reportable segments offer different products and services and are managed separately as business units. Accounting policies for Duke Energy’s segments are the same as those described in the Notes to the Consolidated Financial Statements in Duke Energy’s Annual Report on Form 10-K for the year ended December 31, 2005. Management evaluates segment performance based on earnings before interest and taxes (EBIT) from continuing operations, after deducting minority interest expense related to those profits.

On a segment basis, EBIT excludes discontinued operations, represents all profits from continuing operations (both operating and non-operating) before deducting interest and taxes, and is net of the minority interest expense related to those profits. Cash, cash equivalents and short-term investments are managed centrally by Duke Energy, so the associated realized and unrealized gains and losses from foreign currency transactions and interest and dividend income on those balances are excluded from the segments’ EBIT.

Transactions between reportable segments are accounted for on the same basis as unaffiliated revenues and expenses in the accompanying Consolidated Financial Statements.

PART I

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

Business Segment Data ^(a)


	Unaffiliated Revenues			Intersegment Revenues			Total Revenues			Segment EBIT / Consolidated Earnings from Continuing Operations before Income Taxes			Depreciation and Amortization
	(in millions)
Three Months Ended June 30, 2006
U.S Franchised Electric and Gas	$	2,125		$	5		$	2,130		$	351		$	358
Natural Gas Transmission		987			(8	)		979			361			119
Field Services ^(c)		—			—			—			148			—
Commercial Power		449			(2	)		447			20			55
International Energy		250			—			250			26			19
Crescent		85			—			85			174			—

Total reportable segments		3,896			(5	)		3,891			1,080			551
Other		77			48			125			(174	)		13
Eliminations		—			(43	)		(43	)		—			—
Interest expense		—			—			—			(339	)		—
Interest income and other ^(b)		—			—			—			43			—

Total consolidated	$	3,973		$	—		$	3,973		$	610		$	564

Three Months Ended June 30, 2005
U.S. Franchised Electric and Gas	$	1,229		$	5		$	1,234		$	274		$	240
Natural Gas Transmission		720			44			764			304			109
Field Services ^(c)		2,895			(23	)		2,872			164			71
Commercial Power		(2	)		38			36			(16	)		15
International Energy		182			—			182			86			16
Crescent		112			—			112			38			—

Total reportable segments		5,136			64			5,200			850			451
Other		138			7			145			(102	)		11
Eliminations		—			(71	)		(71	)		—			—
Interest expense		—			—			—			(295	)		—
Interest income and other ^(b)		—			—			—			32			—

Total consolidated	$	5,274		$	—		$	5,274		$	485		$	462

Six Months Ended June 30, 2006
U.S. Franchised Electric and Gas	$	3,413		$	9		$	3,422		$	710		$	590
Natural Gas Transmission		2,455			(2	)		2,453			799			241
Field Services ^(c)		—			—			—			292			—
Commercial Power		461			2			463			(7	)		69
International Energy		481			—			481			113			37
Crescent		156			—			156			216			—

Total reportable segments		6,966			9			6,975			2,123			937
Other		208			63			271			(232	)		23
Eliminations		—			(72	)		(72	)		—			—
Interest expense		—			—			—			(589	)		—
Interest income and other ^(b)		—			—			—			52			—

Total consolidated	$	7,174		$	—		$	7,174		$	1,354		$	960

Six Months Ended June 30, 2005
U.S. Franchised Electric and Gas	$	2,489		$	10		$	2,499		$	610		$	495
Natural Gas Transmission		1,875			80			1,955			715			223
Field Services ^(c)		5,470			60			5,530			1,083			143
Commercial Power		(3	)		52			49			(34	)		30
International Energy		350			—			350			154			31
Crescent		176			—			176			90			—

Total reportable segments		10,357			202			10,559			2,618			922
Other		245			(66	)		179			(286	)		21
Eliminations		—			(136	)		(136	)		—			—
Interest expense		—			—			—			(585	)		—
Interest income and other ^(b)		—			—			—			49			—

Total consolidated	$	10,602		$	—		$	10,602		$	1,796		$	943

(a)	Segment results exclude results of any discontinued operations.

(b)	Other includes foreign currency transaction gains and losses, and additional minority interest expense not allocated to the segment results.

(c)

In July 2005, Duke Energy completed the previously announced agreement with ConocoPhillips to reduce Duke Energy’s ownership interest in DEFS from 69.7% to 50%. Field Services segment data includes DEFS as a consolidated entity for the three and six months ended June 30, 2005 and as an equity method investment for the three and six months ended June 30, 2006.

PART I

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

Segment assets in the following table exclude all intercompany assets.

Segment Assets


	June 30, 2006		December 31, 2005
	(in millions)
U.S. Franchised Electric and Gas ^(a)	$	29,408	$	18,739
Natural Gas Transmission		18,968		18,823
Field Services		1,444		1,377
Commercial Power ^(a)(b)		8,036		1,619
International Energy		3,297		2,962
Crescent		1,698		1,507
Unallocated Goodwill ^(d)		4,128		—

Total reportable segments		66,979		45,027
Other ^(b)		3,249		9,402
Reclassifications ^(c)		140		294

Total consolidated assets	$	70,368	$	54,723

(a)	Increase in segment assets primarily attributable to merger with Cinergy

(b)	Includes impacts of reclassification of DENA’s Midwestern power generating assets from Other to Commercial Power

(c)	Represents reclassification of federal tax balances in consolidation.

(d)

Unallocated Goodwill recorded as of June 30, 2006 resulting from Duke Energy’s merger with Cinergy. The valuation and other assessment procedures required to allocate this goodwill to the appropriate reporting units and reportable segments is currently in process and is anticipated to be completed by the end of 2006. While the allocation is not yet complete, Duke Energy anticipates that the goodwill will be allocated to the U.S. Franchised Electric and Gas and Commercial Power segments, as well as Other, with at least half of the goodwill likely relating to the U.S. Franchised Electric and Gas segment.

15. Risk Management Instruments

The following table shows the carrying value of Duke Energy’s derivative portfolio as of June 30, 2006, and December 31, 2005.

Derivative Portfolio Carrying Value


	June 30, 2006			December 31, 2005
	(in millions)
Hedging	$	(23	)	$	(17	)
Trading		1			5
Undesignated		(98	)		(53	)

Total	$	(120	)	$	(65	)

The amounts in the table above represent the combination of assets and (liabilities) for unrealized gains and losses on mark-to-market and hedging transactions on Duke Energy’s Consolidated Balance Sheets, excluding approximately $901 million of derivative assets and $770 million of derivative liabilities are presented as assets and liabilities held for sale at June 30, 2006.

The $45 million decrease in the undesignated derivative portfolio fair value is due primarily to termination of DENA’s sleeved transactions, primarily Barclay’s, partially offset by realized losses on certain contracts held by Duke Energy related to Field Services’ commodity price risk. As a result of the transfer of 19.7% interest in DEFS to ConocoPhillips and the third quarter 2005 deconsolidation of its investment in DEFS, Duke Energy has discontinued hedge accounting for certain contracts held by Duke Energy related to Field Services’ commodity price risk, which were previously accounted for as cash flow hedges. These contracts were originally entered into as hedges of forecasted future sales by Field Services, and have been retained as undesignated derivatives. Since discontinuance of hedge accounting, these contracts have been marked-to-market in the Consolidated Statements of Operations. As a result, approximately $250 million of pre-tax losses were recognized in earnings by Duke Energy as of June 30, 2005. These charges have been classified in the accompanying Consolidated Statements of Operations as follows: upon discontinuance of hedge accounting approximately $120 million of pre-tax losses were recognized as a component of Impairments and Other Charges, while approximately $20 million and $130 million of pre-tax losses were recognized prior to the deconsolidation of DEFS as a component of Non-Regulated Electric, Natural Gas, Natural Gas Liquids, and Other Revenues for the three and six months ended June 30, 2005, respectively. Approximately $21 million and $45 million of realized and unrealized pre-tax losses related to these contracts were recognized in earnings by Duke Energy during the three and six months ended June 30, 2006, respectively as a component of Other Income and Expenses, net as of a result of Duke Energy’s investment in DEFS being accounted for using the equity method. Cash settlements on these contracts during the six months ended

PART I

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

June 30, 2006 of approximately $90 million are classified as a component of net cash used in investing activities in the accompanying Consolidated Statements of Cash Flows.

Included in Other Current Assets in the Consolidated Balance Sheets as of June 30, 2006 and December 31, 2005 are collateral assets of approximately $141 million and $1,279 million, respectively, excluding approximately $263 million which was reclassified to held for sale associated with the announced sale of Cinergy Marketing and Trading, LP. Collateral assets represent cash collateral posted by Duke Energy with other third parties. Included in Other Current Liabilities and Other Deferred Credits and Other Liabilities in the Consolidated Balance Sheets as of June 30, 2006 and December 31, 2005 are collateral liabilities of approximately $294 million and $708 million, respectively, excluding approximately $15 million which was reclassified to held for sale primarily associated with the announced sale of Cinergy Marketing and Trading, LP. Collateral liabilities represent cash collateral posted by other third parties to Duke Energy. Subsequent to December 31, 2005, in connection with the sale to Barclays of contracts related to DENA’s energy marketing and management activities, which includes structured power and other contracts, Barclays provided DENA cash equal to the net collateral posted by DENA under the contracts. Net cash collateral received by Duke Energy in January 2006 was approximately $540 million based on current market prices of the contracts (see Note 13).

During the first quarter of 2005, Duke Energy settled certain hedges which were documented and designated as net investment hedges of the investment in Westcoast on their scheduled maturity and paid approximately $162 million. Losses recognized on this net investment hedge have been classified in AOCI as a component of foreign currency adjustments and will not be recognized in earnings unless the complete or substantially complete liquidation of Duke Energy’s investment in Westcoast occurs.

Commodity Cash Flow Hedges. Some Duke Energy subsidiaries are exposed to market fluctuations in the prices of various commodities related to their ongoing power generating and natural gas gathering, distribution, processing and marketing activities. Duke Energy closely monitors the potential impacts of commodity price changes and, where appropriate, enters into contracts to protect margins for a portion of future sales and generation revenues and fuel expenses. Duke Energy uses commodity instruments, such as swaps, futures, forwards and options as cash flow hedges for natural gas, electricity and natural gas liquid transactions. Duke Energy’s hedging exposures to the price variability of these commodities does not extend beyond one year.

As of June 30, 2006, $42 million of the pre-tax deferred net losses on derivative instruments related to commodity cash flow hedges were accumulated on the Consolidated Balance Sheet in AOCI, and are expected to be recognized in earnings during the next 12 months as the hedged transactions occur. However, due to the volatility of the commodities markets, the corresponding value in AOCI will likely change prior to its reclassification into earnings.

The ineffective portion of commodity cash flow hedges resulted in the recognition of a pre-tax gain of approximately $10 million and an immaterial amount in the three and six months ended June 30, 2006, respectively, as compared to a pre-tax loss of approximately $11 million and $30 million in the three and six months ended June 30, 2005, respectively. The amount recognized for transactions that no longer qualified as cash flow hedges was a pre-tax loss of approximately $67 million as of June 30, 2006 and was a pre-tax loss of approximately $120 million as of June 30, 2005, and are reported in Loss From Discontinued Operations, net of tax and Impairments and Other Charges in the Consolidated Statements of Operations, respectively.

Commodity Fair Value Hedges. Some Duke Energy subsidiaries are exposed to changes in the fair value of some unrecognized firm commitments to sell generated power or natural gas due to market fluctuations in the underlying commodity prices. Duke Energy actively evaluates changes in the fair value of such unrecognized firm commitments due to commodity price changes and, where appropriate, uses various instruments to hedge its market risk. These commodity instruments, such as swaps, futures and forwards, serve as fair value hedges for the firm commitments associated with generated power. The ineffective portion of commodity fair value hedges resulted in an immaterial amount and a pre-tax gain of $7 million in the three and six months ended June 30, 2006, respectively, as compared to immaterial amounts in the three and six months ended June 30, 2005, respectively.

16. Regulatory Matters

Regulatory Merger Approvals. As discussed in Note 1 and Note 2, on April 3, 2006, the merger between Duke Energy and Cinergy was consummated to create a newly formed company, Duke Energy Holding Corp. (subsequently renamed Duke Energy Corporation). As a condition to the merger approval, the Public Utilities Commission of Ohio (PUCO), the Kentucky Public Service Commission (KPSC), the Public Service Commission of South Carolina (PSCSC) and the NCUC required that certain merger related savings be shared with customers in Ohio, Kentucky, South Carolina, and North Carolina, respectively. Each of the commissions also required

Duke Energy Holding Corp., Cinergy, CG&E, ULH&P, and/or Duke Power Company LLC (Duke Power) to meet additional conditions. While the merger itself was not subject to approval by the Indiana Utility Regulatory Commission (IURC), the IURC approved, certain affiliate agreements in connection with the merger subject to similar conditions. Key elements of these conditions include:

•

The PUCO’s conditions include a requirement that CG&E provide (i) a rate credit of approximately $15 million for one year to facilitate economic development in a time of increasing rates and (ii) a credit of approximately $21 million to CG&E’s gas and electric customers in Ohio for one year, with both credits beginning January 1, 2006. In April 2006, the Office of the Ohio Consumers’ Council (OCC) filed a Notice of Appeal with the Supreme Court of Ohio, requesting the Court remand the PUCO’s merger approval for a full evidentiary hearing. The OCC alleged that the PUCO committed reversible error on both procedural and substantive grounds by, among other things, failing to set the matter for a full evidentiary hearing, failing to consider evidence regarding the transfer of certain DENA assets to CG&E, and failing to lift the stay on discovery. CG&E and the OCC have resolved this matter through settlement and in May 2006, the OCC filed a motion to dismiss. In June 2006, the court granted the motion to dismiss. As of June 30, 2006, CG&E has returned $7 million and $9 million, respectively, on each of these rate credits

•

The KPSC’s conditions include a requirement that ULH&P provide $7.6 million in rate credits to ULH&P customers over five years, ending when new rates are established in the next rate case after January 1, 2008. As of June 30, 2006, ULH&P has returned $1 million to customers on this rate credit.

•

The PSCSC’s conditions include a requirement that Duke Power provide a $40 million rate reduction for one year and a three-year extension to the Bulk Power Marketing profit sharing arrangement. Approximately $3 million of the rate reduction have been passed through to customers since the ruling by the PSCSC.

•

The NCUC’s conditions include a requirement that Duke Power provide (i) a rate reduction of approximately $117.5 million for Duke Power’s North Carolina customers through a credit rider to existing base rates for a one-year period following the close of the merger, and (ii) $12 million to support various low income, environmental, economic development and educationally beneficial programs , the cost of which was incurred in the second quarter of 2006.

In its order approving Duke Energy’s merger with Cinergy, the NCUC stated that the merger will result in a significant change in Duke Energy’s organizational structure which constitutes a compelling factor that warrants a general rate review. Therefore, as a condition of its merger approval and no later than June 2007, Duke Power is required to file a general rate case or demonstrate that Duke Power’s existing rates and charges should not be changed. This review will be consolidated with the proceeding that the NCUC is required to undertake in connection with the North Carolina clean air legislation to review the company’s environmental compliance costs. The NCUC specifically noted that it has made no determination that the rates currently being charged by Duke Power are in fact unjust or unreasonable.

•

The IURCs conditions include a requirement that PSI provide a rate credit of $40 million to PSI customers over a one year period and $5 million for low-income energy assistance and clean coal technology. In April 2006, Citizens Action Coalition of Indiana, Inc., an intervenor in the merger proceeding, filed a Verified Petition for Rehearing and Reconsideration claiming that PSI should be ordered to provide an additional $5 million in rate credits to customers to be consistent with the terms of the NCUC’s order approving the merger. In May 2006, the IURC denied the petition for rehearing and reconsideration. As of June 30, 2006, PSI has returned $3 million to customers on this rate credit.

•

The FERC approved the merger without conditions. On January 19, 2006, Public Citizen’s Energy Program, Citizens Action Coalition of Indiana, Inc., Ohio Partners for Affordable Energy and Southern Alliance for Clean Energy requested rehearing of the FERC approval. On February 21, 2006, the FERC issued an order granting rehearing of FERC’s order for further consideration. A decision by FERC is expected in the third quarter of 2006.

U.S. Franchised Electric and Gas. Rate Related Information. The NCUC, PSCSC, PUCO, IURC and KPSC approve rates for retail electric and gas sales within their states. The FERC approves rates for electric sales to regulated wholesale customers.

NC Clean Air Act Compliance. In 2002, the state of North Carolina passed clean air legislation that freezes electric utility rates from June 20, 2002 to December 31, 2007 (rate freeze period), subject to certain conditions, in order for North Carolina electric utilities, including Duke Power, to significantly reduce emissions of sulfur dioxide (SO ₂ ) and nitrogen oxides (NOx) from coal-fired power plants in the state. The legislation allows electric utilities, including Duke Power, to accelerate the recovery of compliance costs by amortizing them over seven years (2003-2009). The legislation provides for significant flexibility in the amount of annual amortization recorded, allowing utilities to vary the amount amortized, within limits, although the legislation does require that a minimum of 70% of the originally

PART I

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estimated total cost of $1.5 billion be amortized within the rate freeze period (2002 to 2007). Duke Powers’ amortization expense related to this clean air legislation totals approximately $763 million from inception, with approximately $63 million and $71 million recorded in the second quarter of 2006 and 2005, respectively, and approximately $125 million and $156 million recorded for the first six months of 2006 and 2005, respectively. As of June 30, 2006, cumulative expenditures totaled $599 million, with $174 million incurred for the first six months of 2006 and $134 million incurred for the first six months of 2005 and are included in Net Cash Provided by Investing Activities on the Consolidated Statements of Cash Flows. In recent filings with the NCUC, Duke Energy Carolinas has estimated the costs to comply with the legislations as approximately $1.7 billion. Actual costs may be higher or lower than the estimate based on changes in construction costs, final federal and state environmental regulations, including, among other things, the North Carolina Clean Air legislation and the Clean Air Interstate Rule, and Duke Energy Carolinas’ continuing analysis of its overall environmental compliance plan. Any change in compliance costs will be included in future filings with the NCUC.

PSI Environmental Compliance Case. In November 2004, PSI applied to the IURC for approval of its plan for complying with sulfur dioxide (SO ₂ ), nitrogen oxides (NO _X ), and mercury emission reduction requirements. PSI also requested approval of cost recovery for certain proposed compliance projects. An evidentiary hearing was held in May 2005. In December 2005, PSI, the Indiana Office of Utility Consumer Counselor (OUCC), and the PSI Industrial Group filed a settlement agreement providing for approval of PSI’s compliance plan, and approval of financing, depreciation, and operation and maintenance cost recovery. In May 2006, the IURC approved the settlement agreement in its entirety. The approved Settlement Agreement provides for: (1) the construction of Phase 1 Clean Air Interstate Rule (CAIR) and Clean Air Mercury Rule (CAMR) projects with estimated expenditures of approximately $1.08 billion, (2) timely recovery of financing, construction, operation and maintenance cost and depreciation associated with the Phase 1 CAIR and CAMR plan, (3) recovery of emission allowances in connection with SO2, NOx and mercury, (4) accelerated 20 year depreciation rate, (5) timely recovery of Phase 1 plan development and presentation costs and Phase 2 costs, and (6) authority to defer post-in-service AFUDC, depreciation costs and operation and maintenance cost until applicable costs are reflected in rates.

CG&E Electric Rate Filings. CG&E operates under a Market Based Standard Service Order (MBSSO) which was approved by the PUCO in November 2004. In March 2005, the OCC appealed the Commission’s approval of the MBSSO to the Supreme Court of Ohio. The Supreme Court of Ohio recently ruled on the MBSSO’s for two other Ohio utilities, and in each of those rulings, upheld the market prices charged by the utility to its consumers as approved by the Commission but overturned the competitive bid process approved by the Commission on the basis that the Commission rejected the bid price on behalf of consumers and the applicable statute requires customer involvement. CG&E’s MBSSO does not contain a competitive bid process pursuant to a statutory exception. CG&E does not expect a significant, if any, change to its MBSSO as a result of this case but cannot predict the outcome of its case. Duke Energy and CG&E expect the court to decide the case in 2006. On August 2, 2006, CG&E filed an application with the PUCO to extend CG&E’s MBSSO. The proposal provides for continued electric system reliability, a simplified rate structure and clear price signals for customers, while helping to maintain a stable revenue stream for CG&E. The application also proposes that the PUCO review and approve the application by the end of 2006.

CG&E’s MBSSO includes a fuel clause recovery component which is audited annually by the PUCO. In January 2006, CG&E entered into a settlement resolving all open issues identified in the 2005 audit. The PUCO approved the settlement in February 2006. Duke Energy and CG&E do not expect the agreement to have a material impact on their consolidated results of operations.

CG&E filed a distribution rate case to recover certain distribution costs with rates becoming effective on January 1, 2006 and CG&E has deferred certain costs in 2004 and 2005 pursuant to its MBSSO. The parties to the proceeding agreed upon and filed a settlement setting the recommended annual revenue increase at approximately $50 million. In December 2005, the PUCO issued an order approving the settlement agreement.

ULH&P Electric Rate Case. In May 2006, ULH&P filed an application for an increase in its base electric rates. The application, which seeks an increase of approximately $65 million in revenue, or approximately 28 percent, to be effective in January 2007 was filed pursuant to the KPSC’s 2003 Order approving the transfer of 1,100 MW of generating assets from CG&E to ULH&P. ULH&P is also seeking to reinstitute its fuel cost recovery mechanism which has been frozen since 2001, and has proposed to refresh the pricing for the back-up supply contract to reflect current market pricing. After ULH&P supplemented its filing in June 2006, the KPSC issued an order in

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June 2006, shortening the notice period for new rates from 30 to 20 days and suspending rates for six months, until January 6, 2007. At this time, Duke Energy and ULH&P cannot predict the outcome of this proceeding.

ULH&P Gas Rate Case. In 2002, the KPSC approved ULH&P’s gas base rate case which included, among other things, recovery of costs associated with an accelerated gas main replacement program. The approval authorized a tracking mechanism to recover such costs including depreciation and a rate of return on the program’s capital expenditures. The Kentucky Attorney General has appealed to the Franklin Circuit Court the KPSC’s approval of the tracking mechanism. In 2005, both ULH&P and the KPSC requested that the court dismiss the case. At the present time, Duke Energy and ULH&P cannot predict the timing or outcome of this litigation.

In February 2005, ULH&P filed a gas base rate case with the KPSC requesting approval to continue the tracking mechanism and for a $14 million annual increase in base rates. A portion of the increase is attributable to including recovery of the current cost of the accelerated main replacement program in base rates. The KPSC did not rule on the base rate case request or the request to continue the tracking mechanism by October 1, 2005; consequently the initial tracking mechanism expired on September 30, 2005. In accordance with Kentucky law, ULH&P implemented the full amount of the requested rate increase on October 1, 2005. In December 2005, the KPSC approved an annual rate increase of $8.1 million and re-approved the tracking mechanism through 2011. Pursuant to the KPSC’s order, ULH&P filed a refund plan in January 2006 for the excess revenues collected since October 1, 2005. In February 2006, the KPSC issued an additional order responding to a rehearing request made by the Attorney General. Its rehearing order approved ULH&P’s refund plan, which resulted in refunds being provided to customers beginning in March 2006. In February 2006, the Attorney General appealed the KPSC’s order to the Franklin Circuit Court, claiming that the order improperly allows ULH&P to increase its rates for gas main replacement costs in between general rate cases, and also claiming that the order improperly allows ULH&P to earn a return on investment for the costs recovered under the tracking mechanism which permits ULH&P to recover its gas main replacement costs. At this time, Duke Energy and ULH&P cannot predict the outcome of this litigation.

Bulk Power Marketing (BPM) Profit Sharing . The NCUC approved Duke Power’s proposal in June, 2004 to share an amount equal to fifty percent of the North Carolina retail allocation of the profits from certain wholesale sales of bulk power from Duke Power’s generating units at market based rates (BPM Profits). Duke Power also informed the NCUC that it would no longer include BPM Profits in calculating its North Carolina retail jurisdictional rate of return for its quarterly reports to the NCUC. As approved by the NCUC, the sharing arrangement provides for fifty percent of the North Carolina allocation of BPM Profits to be distributed through various assistance programs, up to a maximum of $5 million per year. Any amounts exceeding the maximum are used to reduce rates for industrial customers in North Carolina.

On June 28, 2006, the NCUC issued an order ruling on a dispute with the Carolina Utility Customers Association (CUCA) and the North Carolina Public Staff on Duke Power’s method for determining the incremental costs of emission allowances used to calculate the BPM Profits for sharing. The NCUC agreed with the Public Staff’s method and ordered Duke Power to file a revised rate rider on June 29, 2006 and to implement the new rider effective July 1, 2006. The Public Staff’s method results in higher BPM Profits to be shared for the period beginning with January 1, 2005. It also is not the method contemplated by Duke Power when it initiated the sharing program and it results in a greater sharing of the profits earned in the January 2005 to December 2005 sharing period than proposed by Duke Power when the program was first approved. This resulted in an $18 million charge during the six months ended June 30, 2006, of which $11 million related to wholesale sales in 2005. On June 29, 2006, Duke Power filed a motion to postpone the effective date of the NCUC’s order to allow time for Duke Power to consider its options and to in any event gather the necessary data to employ the Public Staff’s method and to implement a revised rider. The NCUC approved Duke Power’s request on June 30. On July 17, 2006, Duke Power filed another motion requesting that the NCUC reconsider its June 28 order. In the alternative, Duke Power requested that the NCUC make its order effective only prospectively with respect to sharing periods beginning January 1, 2007. Duke Power also requested that if the NCUC was not inclined to grant its request to reinstate its proposed rider, then the NCUC should approve Duke Power’s withdrawal of the rider at its option. Duke Power’s request is scheduled for oral arguments on August 29, 2006.

Duke Power’s Fuel Factor. On June 27, 2006, the NCUC issued its order approving a fuel factor of 1.6691 cents/kWh for the July 2006 through June 2007 billing period for Duke Power. The approved factor is a 13% increase from the previously approved net fuel factor of 1.4769 cents/kWh. In approving the fuel factor, the NCUC rejected CUCA’s request for a disallowance of approximately $50

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million because of an alleged failure by Duke Power to diversify the type of coal it burns. An application for a revised fuel factor that will be effective October 2006 to September 2007 in South Carolina was filed on July 27, 2006. A hearing on the application is scheduled for August 2006.

Other. U.S. Franchised Electric and Gas is engaged in planning efforts to meet projected load growth in its service territory. Long-term projections indicate a need for significant capacity additions, which may include new nuclear, integrated gasification combined cycle (IGCC) and coal facilities. Because of the long lead times required to develop such assets, U.S. Franchised Electric and Gas is taking steps now to ensure those options are available. In March 2006, Duke Power announced that it has entered into an agreement with Southern Company to evaluate potential construction of a new nuclear plant at a site jointly owned in Cherokee County, South Carolina. With selection of the Cherokee County site, Duke Power is moving forward with previously announced plans to develop an application to the U.S. Nuclear Regulatory Commission (NRC) for a combined construction and operating license (COL) for two Westinghouse AP1000 (advanced passive) reactors. Each reactor is capable of producing approximately 1,117 megawatts. The COL application submittal to the NRC is anticipated in late 2007 or early 2008. Submitting the COL application does not commit Duke Energy Carolinas to build nuclear units. Duke Power will decide whether to proceed with construction at a later date.

On June 2, 2006, Duke Power also filed an application with the NCUC for a Certificate of Public Convenience and Necessity (“CPCN”) to construct two 800 MW state of the art coal generation units at its existing Cliffside Steam Station in North Carolina. On July 6, 2006, the NCUC issued its scheduling order in this case. It will hold public hearings in August 2006, and an evidentiary hearing in Raleigh, North Carolina in September 2006. Interventions are due in August 2006.

In May 2006, Duke Power announced an agreement to acquire an approximate 825 megawatt power plant located in Rockingham County, North Carolina, from Rockingham Power, LLC, an affiliate of Dynegy for approximately $195 million. The Rockingham plant is a peaking power plant used during times of high electricity demand, generally in the winter and summer months and consists of five 165 megawatt Westinghouse combustion turbine units capable of using either natural gas or oil to operate. The acquisition is consistent with Duke Energy’s plan to meet customers’ electric needs over the next twenty years. The transaction, which is anticipated to close in the fourth quarter of 2006, requires approvals by the NCUC and FERC. In addition, approval is required from either the U.S. Department of Justice or the FTC under the Hart-Scott-Rodino Antitrust Improvement Act. The FTC approved the transaction on July 20, 2006, and the NCUC approved it on July 25, 2006. Application for FERC approval was filed on July 28, 2006 and is pending.

PSI filed an application with the IURC for approval of study and preconstruction costs related to the joint development of an IGCC project with Southern Indiana Gas and Electric Company d/b/a Vectren Energy Delivery of Indiana, Inc. (Vectren). PSI and Vectren reached a Settlement Agreement with the Indiana Office of Utility Consumer Counselor providing for the recovery of such costs if the IGCC project is approved and constructed and for the partial recovery of such costs if the IGCC project does not go forward. The IURC issued an order on July 26, 2006 approving the Settlement Agreement in its entirety.

Natural Gas Transmission. Rate Related Information . In November 2005, The British Columbia Pipeline System (BC Pipeline) filed an application with the National Energy Board (NEB) for interim and final tolls for 2006. In December 2005, the NEB approved the 2006 interim tolls as filed and BC Pipeline started negotiations with its shippers to reach a settlement on final tolls for years 2006 and 2007. BC Pipeline reached a toll settlement agreement in principle with its customers for the 2006 and 2007 fiscal years on March 30, 2006. The toll settlement agreement was filed with the NEB on June 21, 2006 and on July 11, 2006 pursuant to the NEB’s Revised Guidelines for Negotiated Settlements, the NEB has asked for comments from interested parties due July 26, 2006.

Union Gas has rates that are approved by the OEB. Effective January 1, 2006, Union Gas implemented new rates approved by the OEB in December 2005, reflecting items previously approved. Union Gas’ earnings for 2006 continue to be subject to the earnings sharing mechanism implemented by the OEB in 2005.

In December 2005, Union Gas filed an application with the OEB for new rates effective January 1, 2007. In May 2006, Union Gas reached a comprehensive agreement with intervenors on all financial issues, except storage regulation and Demand Side Management (DSM), and on most non-financial issues. Storage regulation and DSM are being addressed through separate proceedings initiated by the OEB. The OEB accepted this agreement on May 23, 2006. The result of the agreement is an average rate increase of approximately 2.7% effective January 1, 2007. The agreement includes an increase in the common equity component of Union Gas’ capital structure, from 35% to 36%. A decision on the remaining non-financial issues was issued by the OEB on June 29, 2006. Rates for the sale of gas are adjusted quarterly to reflect updated commodity price forecasts. The difference between the approved and the actual cost of gas

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incurred in the current period is deferred for future recover from or return to customers, subject to approval by the OEB. These differences are directly flowed through to customers and, therefore, no rate of return is earned on the related deferred balances. The OEB’s review and approval of these gas purchase costs primarily considers the prudence of the cost incurred.

Effective January 1, 2005, new rates (interim rates) for Maritimes & Northeast Pipeline L.L.C. (M&N) took effect, subject to refund, as a result of a rate case filed by M&N in 2004. In June 2005, a settlement agreement to resolve the proceeding was reached with customers that would provide for a rate increase over rates charged prior to January 1, 2005. On May 15, 2006 the FERC issued an order approving the settlement agreement. In June 2006, M&N refunded the difference between the settlement rates and the interim rates, plus interest, to each shipper due a refund.

Management believes that the effects of these matters will have no material adverse effect on Duke Energy’s future consolidated results of operations, cash flows or financial position.

17. Commitments and Contingencies

Environmental

Duke Energy is subject to international, federal, state and local regulations regarding air and water quality, hazardous and solid waste disposal and other environmental matters.

Remediation activities. Like others in the energy industry, Duke Energy and its affiliates are responsible for environmental remediation at various contaminated sites. These include some properties that are part of ongoing Duke Energy operations, sites formerly owned or used by Duke Energy entities, and sites owned by third parties. Remediation typically involves management of contaminated soils and may involve groundwater remediation. Managed in conjunction with relevant federal, state and local agencies, activities vary with site conditions and locations, remedial requirements, complexity and sharing of responsibility. If remediation activities involve statutory joint and several liability provisions, strict liability, or cost recovery or contribution actions, Duke Energy or its affiliates could potentially be held responsible for contamination caused by other parties. In some instances, Duke Energy may share liability associated with contamination with other potentially responsible parties, and may also benefit from insurance policies or contractual indemnities that cover some or all cleanup costs. All of these sites generally are managed in the normal course of business or affiliate operations. Management believes that completion or resolution of these matters will have no material adverse effect on Duke Energy’s consolidated results of operations, cash flows or financial position.

Clean Water Act. The U. S. Environmental Protection Agency’s (EPA’s) final Clean Water Act Section 316(b) rule became effective July 9, 2004. The rule establishes aquatic protection requirements for existing facilities that withdraw 50 million gallons or more of water per day from rivers, streams, lakes, reservoirs, estuaries, oceans, or other U.S. waters for cooling purposes. Eight of Duke Energy’s eleven coal and nuclear-fueled generating facilities in North Carolina and South Carolina, and its three natural gas-fired generating facilities in California are affected sources under the rule. The three California facilities are part of the DENA business and were sold as part of the transaction announced in January 2006 that closed in May 2006 (see Note 13). Six of Cinergy’s eleven coal-fueled generating facilities in which Cinergy is either a whole or partial owner are affected sources under the rule. The rule requires a Comprehensive Demonstration Study (CDS) for each affected facility to provide information needed to determine necessary facility-specific modifications and cost estimates for implementation. These studies will be completed over the next three to five years. Once compliance measures are determined and approved by regulators, a facility will typically have five or more years to implement the measures. Due to the wide range of measures potentially applicable to a given facility, and since the final selection of compliance measures will be at least partially dependent upon the CDS information, Duke Energy is not able to estimate its cost for complying with the rule at this time.

Clean Air Mercury Rule. The EPA finalized its final Clean Air Mercury Rule (CAMR) in [May] 2005. The rule limits total annual mercury emissions from coal-fired power plants across the United States through a two-phased cap-and-trade program. Phase 1 begins in 2010 and Phase 2 begins in 2018. The rule gives states the option of participating in the national trading program. If a state chooses not to participate, then the rule sets a fixed limit on that state’s annual emissions. The emission controls Duke Energy is installing to comply with North Carolina clean air legislation will contribute significantly to achieving compliance with the CAMR requirements. Duke Energy currently estimates that the additional cost of complying with Phase 1 of the CAMR will have no material adverse effect on Duke Energy’s consolidated results of operations, cash flows or financial position, and is currently unable to estimate the cost of complying with Phase 2 of the CAMR.

Clean Air Interstate Rule. The EPA finalized its Clean Air Interstate Rule (CAIR) in [May] 2005. The rule limits total annual SO ₂ and NOx emissions from electric generating facilities across the Eastern United States through a two-phased cap-and-trade program. Phase 1

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begins in 2009 for NOx and in 2010 for SO ₂ . Phase 2 begins in 2015 for both NOx and SO ₂ . The rule requires SO ₂ and NOx emissions to be cut 70 percent and 65 percent, respectively by 2015. The rule gives states the option of participating in the national trading program. If a state chooses not to participate, then the rule sets a fixed limit on that state’s annual emissions. The emission controls that Duke Energy is installing to comply with North Carolina clean air legislation will contribute significantly to achieving compliance with the CAIR requirements. Duke Energy currently estimates that the additional cost of complying with Phase 1 of the CAIR will have no material adverse effect on Duke Energy’s consolidated results of operations, cash flows or financial position, and is currently unable to estimate the cost of complying with Phase 2 of the CAIR. On July 11, 2005, Duke Energy and others filed petitions with the U.S. Court of Appeals for the District of Columbia Circuit requesting the Court to review certain elements of the EPA’s CAIR. Duke Energy is seeking to have the EPA revise the method of allocating SO ₂ emission allowances to entities under the rule.

Extended Environmental Activities, Accruals. Included in Other Current Liabilities and Other Deferred Credits and Other Liabilities on the Consolidated Balance Sheets were total accruals related to extended environmental-related activities of approximately $70 million and $55 million as of June 30, 2006 and December 31, 2005, respectively. These accruals represent Duke Energy’s provisions for costs associated with remediation activities at some of its current and former sites, as well as other relevant environmental contingent liabilities. Management believes that completion or resolution of these matters will have no material adverse effect on Duke Energy’s consolidated results of operations, cash flows or financial position.

Litigation

New Source Review (NSR)/EPA Litigation. In 2000, the U.S. Justice Department, acting on behalf of the EPA, filed a complaint against Duke Energy in the U.S. District Court in Greensboro, North Carolina, for alleged violations of the Clean Air Act (CAA). The EPA claims that 29 projects performed at 25 of Duke Energy’s coal-fired units were major modifications, as defined in the CAA, and that Duke Energy violated the CAA when it undertook those projects without obtaining permits and installing emission controls for SO ₂ , NOx and particulate matter. The complaint asks the Court to order Duke Energy to stop operating the coal-fired units identified in the complaint, install additional emission controls and pay unspecified civil penalties. Duke Energy asserts that there were no CAA violations because the applicable regulations do not require permitting in cases where the projects undertaken are “routine” or otherwise do not result in a net increase in emissions. In August 2003, the trial Court issued a summary judgment opinion adopting Duke Energy’s legal positions, and on April 15, 2004, the Court entered Final Judgment in favor of Duke Energy. The government appealed the case to the U.S. Fourth Circuit Court of Appeals. On June 15, 2005, the Fourth Circuit ruled in favor of Duke Energy and effectively adopted Duke Energy’s view that permitting of projects is not required unless the work performed implicates a net increase in the hourly rate of emissions. The EPA filed a request for rehearing with the Fourth Circuit, which was denied. The EPA decided not to petition the U.S. Supreme Court to hear an appeal of the matter. Some environmental groups who intervened in the early stages in the case have filed their petition for appeal. The Supreme Court has elected to hear this matter and oral argument is expected to be scheduled in the fourth quarter of 2006.

In November 1999, and through subsequent amendments, the United States brought a lawsuit in the United States Federal District Court for the Southern District of Indiana against Cinergy, CG&E, and PSI alleging various violations of the CAA. Specifically, the lawsuit alleges that Duke Energy violated the CAA by not obtaining Prevention of Significant Deterioration (PSD), Non-Attainment New Source Review, and Ohio and Indiana SIP permits for various projects at Duke Energy owned and co-owned generating stations. Additionally, the suit claims that Duke Energy violated an Administrative Consent Order entered into in 1998 between the EPA and Cinergy relating to alleged violations of Ohio’s SIP provisions governing particulate matter at Unit 1 at CG&E’s W.C. Beckjord Station. The suit seeks (1) injunctive relief to require installation of pollution control technology on various generating units at CG&E’s W.C. Beckjord and Miami Fort Stations, and PSI’s Cayuga, Gallagher, Wabash River, and Gibson Stations, and (2) civil penalties in amounts of up to $27,500 per day for each violation. In addition, three northeast states and two environmental groups have intervened in the case. In August 2005, the district court issued a ruling regarding the emissions test that it will apply to Cinergy, CG&E, and PSI at the trial of the case. Contrary to Cinergy’s, CG&E’s, and PSI’s argument, the district court ruled that in determining whether a project was projected to increase annual emissions, it would not hold hours of operation constant. However, the district court subsequently certified the matter for interlocutory appeal to the Seventh Circuit Court of Appeals, which has accepted the appeal. Oral arguments were held before the Seventh Circuit Court of Appeals in June 2006. In February 2006, the district court ruled that in carrying its burden of proof, the defendant can look to industry practice in proving a particular project was routine. The district court has removed the trial from the calendar and will reset a trial date, if necessary, after the Seventh Circuit rules. Notwithstanding the appeal, there are a number of other legal issues currently before the district court judge.

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In March 2000, the United States also filed in the United States District Court for the Southern District of Ohio an amended complaint in a separate lawsuit alleging violations of the CAA relating to PSD, NSR, and Ohio SIP requirements regarding various generating stations, including a generating station operated by Columbus Southern Power Company (CSP) and jointly-owned by CSP, The Dayton Power and Light Company (DP&L), and CG&E. The EPA is seeking injunctive relief and civil penalties of up to $27,500 per day for each violation. This suit is being defended by CSP. In April 2001, the United States District Court for the Southern District of Ohio in that case ruled that the Government and the intervening plaintiff environmental groups cannot seek monetary damages for alleged violations that occurred prior to November 3, 1994; however, they are entitled to seek injunctive relief for such alleged violations. Neither party appealed that decision. This matter was heard in trial in July 2005. A decision is pending.

In addition, Cinergy and CG&E have been informed by DP&L that in June 2000, the EPA issued a Notice of Violation (NOV) to DP&L for alleged violations of PSD, NSR, and Ohio SIP requirements at a station operated by DP&L and jointly-owned by DP&L, CSP, and CG&E. The NOV indicated the EPA may (1) issue an order requiring compliance with the requirements of the Ohio SIP, or (2) bring a civil action seeking injunctive relief and civil penalties of up to $27,500 per day for each violation. In September 2004, Marilyn Wall and the Sierra Club brought a lawsuit against CG&E, DP&L and CSP for alleged violations of the CAA at this same generating station. This case is currently in discovery in front of the same judge who has the CSP case.

In July 2004, the states of Connecticut, New York, California, Iowa, New Jersey, Rhode Island, Vermont, Wisconsin, and the City of New York brought a lawsuit in the United States District Court for the Southern District of New York against Cinergy, American Electric Power Company, Inc., American Electric Power Service Corporation, The Southern Company, Tennessee Valley Authority, and Xcel Energy Inc. A similar lawsuit was filed in the United States District Court for the Southern District of New York against the same companies by Open Space Institute, Inc., Open Space Conservancy, Inc., and The Audubon Society of New Hampshire. These lawsuits allege that the defendants’ emissions of CO ₂ from the combustion of fossil fuels at electric generating facilities contribute to global warming and amount to a public nuisance. The complaints also allege that the defendants could generate the same amount of electricity while emitting significantly less CO ₂ . The plaintiffs are seeking an injunction requiring each defendant to cap its CO ₂ emissions and then reduce them by a specified percentage each year for at least a decade. In September 2005, the district court granted the defendants’ motion to dismiss the lawsuit. The plaintiffs have appealed this ruling to the Second Circuit Court of Appeals. Oral argument was held before the Second Circuit Court of Appeals on June 7, 2006.

It is not possible to predict with certainty whether Duke Energy will incur any liability or to estimate the damages, if any, that Duke Energy might incur in connection with these matters.

Western Energy and Natural Gas Litigation and Regulatory Matters. Duke Energy and several of its affiliates, as well as other energy companies, are parties to 34 lawsuits filed by or on behalf of electricity and/or natural gas purchasers in several Western states. Many of the suits seek class-action certification. The plaintiffs allege that the defendants conspired to manipulate the electricity and/or natural gas markets in violation of state and/or federal antitrust, unfair business practices and other laws. Plaintiffs in some of the cases further allege that such activities, including engaging in “round trip” trades, providing false information to natural gas trade publications and unlawfully exchanging information, resulted in artificially high energy prices. Plaintiffs seek aggregate damages or restitution of billions of dollars from the defendants. Six of these cases were dismissed on filed rate and/or federal preemption grounds, and the plaintiffs in each of these dismissed cases have appealed their respective rulings to the U.S. Ninth Circuit Court of Appeals. It is not possible to predict with certainty whether Duke Energy will incur any liability or to estimate the damages, if any, that Duke Energy might incur in connection with these lawsuits, but Duke Energy does not presently believe the outcome of these matters will have a material adverse effect on its consolidated results of operations, cash flows or financial position.

In 2002, Southern California Edison Company (SCE) initiated arbitration proceedings regarding disputes with DETM relating to amounts owed in connection with the termination of bi-lateral power contracts between the parties in early 2001. This matter proceeded to hearing in November 2005. In January 2006, the parties reached an agreement in principle to resolve the matters at issue in the arbitration. The parties entered into a Settlement Agreement and Mutual Release dated as of March 10, 2006, and on March 24, 2006, DETM paid the settlement amount, including interest, into escrow. The agreement will require regulatory approval. Based on the terms of the Settlement Agreement and Mutual Release, Duke Energy does not expect that the resolution of this matter will have a material adverse effect on its consolidated results of operations, cash flows or financial position.

Trading Related Litigation. Commencing August 2003, plaintiffs filed three class-action lawsuits in the U.S. District Court for the Southern District of New York on behalf of entities who bought and sold natural gas futures and options contracts on the New York

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Mercantile Exchange during the years 2000 through 2002. DETM, along with numerous other entities, is named as a defendant. The plaintiffs claim that the defendants violated the Commodity Exchange Act by reporting false and misleading trading information to trade publications, resulting in monetary losses to the plaintiffs. Plaintiffs seek class action certification, unspecified damages and other relief. On September 24, 2004, the court denied a motion to dismiss the plaintiffs’ claims filed on behalf of DETM and other defendants, and on September 30, 2005, the court certified the class. Duke Energy has reached an agreement with the plaintiffs in these consolidated cases to resolve all issues and on February 8, 2006, the court granted preliminary approval of this settlement. The Final Judgment and Order of Dismissal were entered in May 2006. The resolution of this matter did not have a material adverse effect on Duke Energy’s consolidated results of operations, cash flows or financial position.

On January 28, 2005, four plaintiffs filed suit in Tennessee Chancery Court against Duke Energy affiliates and other energy companies seeking class action certification on behalf of indirect purchasers of natural gas who allege that they have been harmed by defendants’ manipulation of the natural gas markets by various means, including providing false information to natural gas trade publications and unlawfully exchanging information, resulting in artificially high natural gas prices paid by plaintiffs in the State of Tennessee. Alleging that defendants violated state antitrust laws and other laws, plaintiffs seek unspecified damages and other relief. Duke Energy is unable to express an opinion regarding the probable outcome of these matters at this time.

On August 8, 2005, a plaintiff filed a lawsuit in state court in Kansas against Duke Energy and DETM, as well as other energy companies. On September 26, 2005, a class action petition was filed in state court in Kansas and on May 19, 2006 another class action petition was filed in Colorado state court. These cases were also filed against Duke Energy and DETM, as well as other energy companies. Each of these cases contains similar claims, that the respective plaintiffs were harmed by the defendants’ alleged manipulation of the natural gas markets by various means, including providing false information to natural gas trade publications and entering into unlawful arrangements and agreements in violation of the antitrust laws of the respective states. Plaintiffs seek damages in unspecified amounts. Duke Energy is unable to express an opinion regarding the probable outcome of these matters at this time.

Trading Related Investigations. Beginning in February 2004, Duke Energy has received requests for information from the U.S. Attorney’s office in Houston focused on the natural gas price reporting activities of certain individuals involved in DETM trading operations. Duke Energy has cooperated with the government in this investigation and is unable to express an opinion regarding the probable outcome at this time.

Sonatrach/Sonatrading Arbitration . Duke Energy LNG Sales Inc. (Duke LNG) claims in an arbitration commenced in January 2001 in London that Sonatrach, the Algerian state-owned energy company, together with its subsidiary, Sonatrading Amsterdam B.V. (Sonatrading), breached their shipping obligations under a liquefied natural gas (LNG) purchase agreement and related transportation agreements (the LNG Agreements) relating to Duke LNG’s purchase of LNG from Algeria and its transportation by LNG tanker to Lake Charles, Louisiana. Duke LNG seeks damages of approximately $27 million. Sonatrading and Sonatrach, on the other hand, claim that Duke LNG repudiated the LNG Agreements by allegedly failing to diligently perform LNG marketing obligations. Sonatrading and Sonatrach seek damages in the amount of approximately $250 million. In 2003, an arbitration tribunal issued a Partial Award on liability issues, finding that Sonatrach and Sonatrading breached their obligations to provide shipping. The tribunal also found that Duke LNG breached the LNG Purchase Agreement by failing to perform marketing obligations. The final hearing on damages was concluded in March 2006 and the parties are awaiting a ruling from the tribunal.

Citrus Trading Corporation (Citrus) Litigation. In conjunction with the Sonatrach LNG Agreements, Duke LNG entered into a natural gas purchase contract (the Citrus Agreement) with Citrus. Citrus filed a lawsuit in March 2003 in the U.S. District Court for the Southern District of Texas against Duke LNG and PanEnergy Corp alleging that Duke LNG breached the Citrus Agreement by failing to provide sufficient volumes of gas to Citrus. Duke LNG contends that Sonatrach caused Duke LNG to experience a loss of LNG supply that affected Duke LNG’s obligations and termination rights under the Citrus Agreement. Citrus seeks monetary damages and a judicial determination that Duke LNG did not experience such a loss. After Citrus filed its lawsuit, Duke LNG terminated the Citrus Agreement and filed a counterclaim asserting that Citrus had breached the agreement by, among other things, failing to provide sufficient security under a letter of credit for the gas transactions. Citrus denies that Duke LNG had the right to terminate the agreement and contends that Duke LNG’s termination of the agreement was itself a breach, entitling Citrus to terminate the agreement and recover damages in the amount of approximately $187 million. The Court has made rulings regarding the issues of fact and law that remain for trial, and the parties have jointly requested a trial setting in December 2006. It is not possible to predict with certainty whether Duke Energy will incur any liability or to estimate the damages, if any, that Duke Energy might incur in connection with the Sonatrach and Citrus matters.

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Notes To Consolidated Financial Statements—(Continued)

Exxon Mobil Disputes. In April 2004, Mobil Natural Gas, Inc. (MNGI) and 3946231 Canada, Inc. (3946231, and collectively with MNGI, Exxon Mobil) filed a Demand for Arbitration against Duke Energy, DETMI, DTMSI Management Ltd. (DTMSI) and other affiliates of Duke Energy. MNGI and DETMI are the sole members of DETM. DTMSI and 3946231 are the sole beneficial owners of Duke Energy Marketing Limited Partnership (DEMLP, and with DETM, the Ventures). Among other allegations, Exxon Mobil alleges that DETMI and DTMSI engaged in wrongful actions relating to affiliate trading, payment of service fees, expense allocations and distribution of earnings in breach of agreements and fiduciary duties relating to the Ventures. Exxon Mobil seeks to recover actual damages, plus attorneys’ fees and exemplary damages; aggregate damages were not specified in the arbitration demand. Duke Energy denies these allegations, and has filed counterclaims asserting that Exxon Mobil breached its Venture obligations and other contractual obligations. By order dated May 2, 2005, the arbitrators granted Duke Energy’s Motion for Partial Summary Judgment, effectively eliminating a significant portion of Exxon Mobil’s claims. Exxon Mobil filed a motion for reconsideration of the ruling as well as for an extension of the date for the arbitration hearing. Exxon Mobil also filed a motion to dismiss certain of Duke Energy’s counterclaims. Following a hearing in December 2005 on the motion for reconsideration, the arbitrators issued their ruling on January 26, 2006, generally reaffirming the original order, with a limited exception with respect to affiliate trades that is not expected to have a significant impact on the case. The panel also dismissed one of Duke Energy’s counterclaims. In response to a request from Exxon Mobil, the arbitration panel has postponed the commencement date of the arbitration hearing from January 2006 to October 2006 in Houston, Texas. In August 2004, DEMLP initiated arbitration proceedings in Canada against certain Exxon Mobil entities asserting that those entities wrongfully terminated two gas supply agreements with the DEMLP and wrongfully failed to assume certain related gas supply agreements with other parties. A hearing in the Canadian arbitration was held in March 2006. The arbitrators issued their award in June, 2006 finding that (1) the two gas supply agreements were improperly terminated by ExxonMobil; but (2) ExxonMobil was not required to take assignment of the related third party gas supply agreements. If DEMLP and ExxonMobil cannot agree on the damages to be paid as the result of the first ruling, the issue will be decided by the same panel of arbitrators. At this time Duke Energy is unable to estimate the amount of any damage award to be received in resolution of this matter. The gas supply agreements with other parties, under which DEMLP continues to remain obligated, are currently estimated to result in losses of between $100 million and $150 million through 2011. However, these losses are subject to adjustment in the future in the event of changes in market conditions and underlying assumptions.

Duke Energy Retirement Cash Balance Plan . A class action lawsuit has been filed in federal court in South Carolina against Duke Energy and the Duke Energy Retirement Cash Balance Plan, alleging violations of Employee Retirement Income Security Act (“ERISA”) and the Age Discrimination in Employment Act. These allegations arise out of the conversion of the Duke Power Company Employees’ Retirement Plan into the Duke Power Company Retirement Cash Balance Plan. The case also raises some Plan administration issues, alleging errors in the application of Plan provisions ( e.g. , the calculation of interest rate credits in 1997 and 1998 and the calculation of lump-sum distributions). The plaintiffs seek to represent present and former participants in the Duke Energy Retirement Cash Balance Plan. This group is estimated to include approximately 36,000 persons. The plaintiffs also seek to divide the putative class into sub-classes based on age. Six causes of action are alleged, ranging from age discrimination, to various alleged ERISA violations, to allegations of breach of fiduciary duty. The plaintiffs seek a broad array of remedies, including a retroactive reformation of the Duke Energy Retirement Cash Balance Plan and a recalculation of participants’/ beneficiaries’ benefits under the revised and reformed plan. Duke Energy filed its answer in March 2006. A second class action lawsuit was filed in federal court in South Carolina, alleging similar claims and seeking to represent the same class of defendants. The second case has been voluntarily dismissed, without prejudice, effectively consolidating it with the first case. It is not possible to predict with certainty whether Duke Energy will incur any liability or to estimate the damages, if any, that Duke Energy might incur in connection with this matter.

Hurricane Katrina Lawsuit. In April 2006, Duke Energy and Cinergy were named in the third amended complaint of a purported class action lawsuit filed in the United States District Court for the Southern District of Mississippi. Plaintiffs claim that Duke Energy and Cinergy, along with numerous other utilities, oil companies, coal companies and chemical companies, are liable for damages relating to losses suffered by victims of Hurricane Katrina. Plaintiffs claim that Duke defendants’, greenhouse gas emissions contributed to the frequency and intensity of storms such as Hurricane Katrina. Neither Duke Energy nor Cinergy has been served with this lawsuit. It is not possible to predict with certainty whether Duke Energy or Cinergy will incur any liability or to estimate the damages, if any, that Duke Energy or Cinergy might incur in connection with this matter.

Asbestos-related Injuries and Damages Claims. Duke Energy has experienced numerous claims relating to damages for personal injuries alleged to have arisen from the exposure to or use of asbestos in connection with construction and maintenance activities conducted by Duke Power Company LLC on its electric generation plants during the 1960s and 1970s. Duke Energy has third-party

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insurance to cover losses related to these asbestos-related injuries and damages above a certain aggregate deductible. The insurance policy, including the policy deductible and reserves, provided for coverage to Duke Energy up to an aggregate of $1.6 billion when purchased in 2000. Probable insurance recoveries related to this policy are classified in the Consolidated Balance Sheets as Other within Investments and Other Assets. Amounts recognized as reserves in the Consolidated Balance Sheets, which are not anticipated to exceed the coverage, are classified in Other Deferred Credits and Other Liabilities and Other Current Liabilities and are based upon Duke Energy’s best estimate of the probable liability for future asbestos claims. These reserves are based upon current estimates and are subject to uncertainty. Factors such as the frequency and magnitude of future claims could change the current estimates of the related reserves and claims for recoveries reflected in the accompanying Consolidated Financial Statements. However, management of Duke Energy does not currently anticipate that any changes to these estimates will have any material adverse effect on Duke Energy’s consolidated results of operations, cash flows or financial position.

PSI and CG&E have been named as defendants or co-defendants in lawsuits related to asbestos at their electric generating stations. Currently, there are approximately 130 pending lawsuits (the majority of which are PSI cases). In these lawsuits, plaintiffs claim to have been exposed to asbestos-containing products in the course of their work as outside contractors in the construction and maintenance of PSI and CG&E generating stations. The plaintiffs further claim that as the property owner of the generating stations, PSI and CG&E should be held liable for their injuries and illnesses based on an alleged duty to warn and protect them from any asbestos exposure. The impact on Duke Energy’s financial position or results of operations of these cases to date has not been material.

Of these lawsuits, one case filed against PSI has been tried to verdict. The jury returned a verdict against PSI on a negligence claim and a verdict for PSI on punitive damages. PSI appealed this decision up to the Indiana Supreme Court. In October 2005, the Indiana Supreme Court upheld the jury’s verdict. PSI paid the judgment of approximately $630,000 in the fourth quarter of 2005. In addition, PSI has settled over 150 other claims for amounts, which neither individually nor in the aggregate, are material to PSI’s financial position or results of operations. Based on estimates under varying assumptions, concerning uncertainties, such as, among others: (i) the number of contractors potentially exposed to asbestos during construction or maintenance of PSI generating plants; (ii) the possible incidence of various illnesses among exposed workers, and (iii) the potential settlement costs without federal or other legislation that addresses asbestos tort actions, Duke Energy estimates that the range of reasonably possible exposure in existing and future suits over the next 50 years could range from an immaterial amount to approximately $60 million, exclusive of costs to defend these cases. This estimated range of exposure may change as additional settlements occur and claims are made in Indiana and more case law is established.

CG&E has been named in fewer than 10 cases and as a result has virtually no settlement history for asbestos cases. Thus, Duke Energy is not able to reasonably estimate the range of potential loss from current or future lawsuits. However, potential judgments or settlements of existing or future claims could be material to Duke Energy.

Other Litigation and Legal Proceedings. Cinergy produces synthetic fuel from two facilities that qualify for tax credits (through 2007) in accordance with Section 29/45K of the Internal Revenue Code if certain requirements are satisfied. These credits reduce Duke Energy’s income tax liability and therefore Duke Energy’s effective tax rate. Cinergy’s sale of synthetic fuel has generated $339 million in tax credits through December 31, 2005. After reducing for the possibility of phase-outs in 2006, the amount of additional credits generated through June 30, 2006 is immaterial. Section 29/45K provides for a phase-out of the credit if the average price of crude oil during a calendar year exceeds a specified threshold. The phase-out is based on a prescribed calculation and definition of crude oil prices. Based on current crude oil prices, Duke Energy believes that for 2006 and 2007 the amount of the tax credits will be reduced, perhaps significantly. Oil prices are currently at a level where Duke Energy has idled the plants, as the value of the credits may not exceed the net costs to produce the synthetic fuel. During the first quarter of 2006, an agreement was in place with the plant operator which would indemnify Duke Energy in the event that tax credits are insufficient to support operating expenses. This agreement did not continue in the second quarter. Duke Energy’s net investment in the plants at June 30, 2006 was approximately $24 million. Based upon the increase in crude oil prices subsequent to June 30, 2006, it is possible that Duke Energy may incur a future impairment of its net investment in the synthetic fuel plants.

The Internal Revenue Service (IRS) has completed the audit of Cinergy for the 2002, 2003, and 2004 tax years including the synfuel facility owned during that period. That facility represents $219 million of tax credits generated during that audit period. The IRS has not proposed any adjustment that would disallow the credits claimed during that period. Subsequent periods are still subject to audit. Duke Energy believes that it operates in conformity with all the necessary requirements to be allowed such credits under Section 29/45K.

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Duke Energy and its subsidiaries are involved in other legal, tax and regulatory proceedings arising in the ordinary course of business, some of which involve substantial amounts. Management believes that the final disposition of these proceedings will not have a material adverse effect on Duke Energy’s consolidated results of operations, cash flows or financial position.

Duke Energy has exposure to certain legal matters that are described herein. As of June 30, 2006, Duke Energy has recorded reserves of approximately $1.25 billion for these proceedings and exposures. Duke Energy has insurance coverage for certain of these losses incurred. As of June 30, 2006, Duke Energy has recognized approximately $1.0 billion of probable insurance recoveries related to these losses. These reserves represent management’s best estimate of probable loss as defined by SFAS No. 5, “Accounting for Contingencies.”

Duke Energy expenses legal costs related to the defense of loss contingencies as incurred.

Other Commitments and Contingencies

Other . As part of its normal business, Duke Energy is a party to various financial guarantees, performance guarantees and other contractual commitments to extend guarantees of credit and other assistance to various subsidiaries, investees and other third parties. These arrangements are largely entered into by Duke Capital LLC (Duke Capital). To varying degrees, these guarantees involve elements of performance and credit risk, which are not included on the Consolidated Balance Sheets. The possibility of Duke Energy or Duke Capital having to honor its contingencies is largely dependent upon future operations of various subsidiaries, investees and other third parties, or the occurrence of certain future events. (For further information see Note 18.)

In addition, Duke Energy enters into various fixed-price, non-cancelable commitments to purchase or sell power (tolling arrangements or power purchase contracts), take-or-pay arrangements, transportation or throughput agreements and other contracts that may or may not be recognized on the Consolidated Balance Sheets. Some of these arrangements may be recognized at market value on the Consolidated Balance Sheets as trading contracts or qualifying hedge positions included in Unrealized Gains or Losses on Mark-to-Market and Hedging Transactions.

See Note 18 for discussion of Calpine guarantee obligation.

18. Guarantees and Indemnifications

Duke Energy and its subsidiaries have various financial and performance guarantees and indemnifications which are issued in the normal course of business. As discussed below, these contracts include performance guarantees, stand-by letters of credit, debt guarantees, surety bonds and indemnifications. Duke Energy and its subsidiaries enter into these arrangements to facilitate a commercial transaction with a third party by enhancing the value of the transaction to the third party.

Duke Capital has issued performance guarantees to customers and other third parties that guarantee the payment and performance of other parties, including certain non-wholly-owned entities. The maximum potential amount of future payments Duke Capital could have been required to make under these performance guarantees as of June 30, 2006 was approximately $637 million. Of this amount, approximately $408 million relates to guarantees of the payment and performance of less than wholly-owned consolidated entities. Approximately $332 million of the performance guarantees expire between 2006 and 2007, with the remaining performance guarantees expiring after 2007 or having no contractual expiration. Additionally, Duke Capital has issued joint and several guarantees to some of the D/FD project owners, guaranteeing the performance of D/FD under its engineering, procurement and construction contracts and other contractual commitments. These guarantees have no contractual expiration and no stated maximum amount of future payments that Duke Capital could be required to make. Additionally, Fluor Enterprises Inc., as 50% owner in D/FD, has issued similar joint and several guarantees to the same D/FD project owners. In accordance with the D/FD partnership agreement, each of the partners is responsible for 50% of any payments to be made under those guarantees.

Duke Capital has issued guarantees to customers or other third parties related to the payment or performance obligations of certain entities that were previously wholly-owned by Duke Energy but which have been sold to third parties, such as DukeSolutions, Inc. (DukeSolutions) and Duke Engineering & Services, Inc. (DE&S). These guarantees are primarily related to payment of lease obligations, debt obligations, and performance guarantees related to provision of goods and services. Duke Energy has received back-to-back indemnification from the buyer of DE&S indemnifying Duke Energy for any amounts paid by Duke Capital related to the DE&S guarantees. Duke Energy also received indemnification from the buyer of DukeSolutions for the first $2.5 million paid by Duke Capital related to the DukeSolutions guarantees. Further, Duke Energy granted indemnification to the buyer of DukeSolutions with respect to losses arising under some energy services agreements retained by DukeSolutions after the sale, provided that the buyer agreed to bear 100% of the

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performance risk and 50% of any other risk up to an aggregate maximum of $2.5 million (less any amounts paid by the buyer under the indemnity discussed above). Additionally, for certain performance guarantees, Duke Energy has recourse to subcontractors involved in providing services to a customer. These guarantees have various terms ranging from 2006 to 2021, with others having no specific term. Duke Energy is unable to estimate the total maximum potential amount of future payments under these guarantees, since some of the underlying agreements have no limits on potential liability.

Cinergy has issued performance guarantees to customers and other third parties that guarantee the payment and performance of certain non-wholly-owned entities. The maximum potential amount of future payments Cinergy Corporation could have been required to make under these performance guarantees as of June 30, 2006 was approximately $113 million. All of the performance guarantees expire after 2007 or have no contractual expiration.

Westcoast Energy, Inc. (Westcoast) has issued performance guarantees to third parties guaranteeing the performance of unconsolidated entities, such as equity method investments, and of entities previously sold by Westcoast to third parties. Those guarantees require Westcoast to make payment to the guaranteed third party upon the failure of such unconsolidated or sold entity to make payment under some of its contractual obligations, such as debt, purchase contracts and leases. The maximum potential amount of future payments Westcoast could have been required to make under those performance guarantees as of June 30, 2006 was approximately $15 million. Of those guarantees, approximately $10 million expire in 2006, with the remainder having no contractual expiration.

Duke Capital uses bank-issued stand-by letters of credit to secure the performance of non-wholly-owned entities to a third party or customer. Under these arrangements, Duke Capital has payment obligations to the issuing bank which are triggered by a draw by the third party or customer due to the failure of the non-wholly-owned entity to perform according to the terms of its underlying contract. The maximum potential amount of future payments Duke Capital could have been required to make under these letters of credit as of June 30, 2006 was approximately $25 million. Substantially all of these letters of credit were issued on behalf of less than wholly-owned consolidated entities and expire in 2006 or 2007.

In connection with Duke Energy’s sale of the Murray merchant generation facility to KGen, in August 2004, Duke Capital guaranteed in favor of a bank the repayment of any draws under a $120 million letter of credit issued by the bank to Georgia Power Company. The letter of credit, which expires in 2006, is related to the obligation of a KGen subsidiary under a seven-year power sales agreement, commencing in May 2005. Duke Capital will be required to ensure reissuance of this letter of credit or issue similar credit support until the power sales agreement expires in 2012. Duke Energy will operate the sold Murray facility under an operation and maintenance agreement with the KGen subsidiary. As a result, the guarantee has an immaterial fair value. Further, KGen has agreed to indemnify Duke Energy for any payments Duke Capital makes with respect to the $120 million letter of credit.

Duke Capital has guaranteed certain issuers of surety bonds, obligating itself to make payment upon the failure of a non-wholly-owned entity to honor its obligations to a third party. As of June 30, 2006, Duke Capital had guaranteed approximately $15 million of outstanding surety bonds related to obligations of non-wholly-owned entities. The majority of these bonds expire in various amounts in 2006.

In 1999, IDC issued approximately $100 million in bonds to purchase equipment for lease to Hidalgo, a subsidiary of Duke Capital. Duke Capital unconditionally and irrevocably guaranteed the lease payments of Hidalgo to IDC through 2028. In 2000, Hidalgo was sold to Calpine Corporation and Duke Capital remained obligated under the lease guaranty. In January 2006, Hidalgo and its subsidiaries filed for bankruptcy protection in connection with the previous bankruptcy filing by its parent, Calpine Corporation in December 2005. Gross, undiscounted exposure under the guarantee obligation as of June 30, 2006 is approximately $200 million, which includes principal and interest. Duke Energy does not believe a loss under the guarantee obligation is probable as of June 30, 2006, but continues to evaluate the situation. Therefore, no reserves have been recorded for any contingent loss as of June 30, 2006. No demands for payment of principal or interest have been made under the guarantee. If future losses are incurred under the guarantee, Duke Capital has certain rights which should allow it to mitigate such loss.

Natural Gas Transmission, International Energy, and Crescent have issued guarantees of debt and performance guarantees associated with non-consolidated entities and less than wholly-owned consolidated entities. If such entities were to default on payments or performance, Natural Gas Transmission, International Energy, or Crescent would be required under the guarantees to make payment on the obligation of the less than wholly-owned entity. As of June 30, 2006, Natural Gas Transmission was the guarantor of approximately $18 million of debt at Westcoast associated with less than wholly-owned entities, which expire in 2019. International Energy was the guarantor of approximately $13 million of performance guarantees associated with less than wholly-owned entities. Substantially all of these guarantees expire between 2006 and 2008. Crescent was the guarantor of approximately $15 million of debt associated with less than wholly-owned entities, which expire in 2006.

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Duke Energy has entered into various indemnification agreements related to purchase and sale agreements and other types of contractual agreements with vendors and other third parties. These agreements typically cover environmental, tax, litigation and other matters, as well as breaches of representations, warranties and covenants. Typically, claims may be made by third parties for various periods of time, depending on the nature of the claim. Duke Energy’s potential exposure under these indemnification agreements can range from a specified amount, such as the purchase price, to an unlimited dollar amount, depending on the nature of the claim and the particular transaction. Duke Energy is unable to estimate the total potential amount of future payments under these indemnification agreements due to several factors, such as the unlimited exposure under certain guarantees.

As of June 30, 2006, the amounts recorded for the guarantees and indemnifications mentioned above are immaterial, both individually and in the aggregate.

In June 2006, the Board of Directors of Duke Energy authorized management to pursue a plan to create two separate publicly traded companies by spinning off Duke Energy’s natural gas business to Duke Energy shareholders. The new gas company, which has yet to be named, would consist of Duke Energy’s Natural Gas Transmission businesses segment, which would include Union Gas, and would also include Duke Energy’s 50-percent ownership interest in DEFS. The businesses remaining in Duke Energy will be the U.S. Franchised Electric and Gas business segment, the Commercial Power business segment, the International business segment and Crescent Resources. Duke Energy is targeting a January 1, 2007 effective date for the transaction. At June 30, 2006, Duke Energy has certain guarantees of wholly-owned subsidiaries that it expects will become guarantees of third party performance upon the separation of the gas and power businesses. Duke Energy expects to receive back-to-back indemnification from the new gas company indemnifying Duke Energy for any amounts paid related to these guarantees.

19. Related Party Transactions

As discussed in Note 2, in February 2005, DEFS sold its wholly-owned subsidiary TEPPCO GP, the general partner of TEPPCO Partners, L.P. (TEPPCO), for approximately $1.1 billion and Duke Energy sold its limited partner interest in TEPPCO for approximately $100 million. Prior to the completion of these sale transactions, Duke Energy accounted for its investment in TEPPCO under the equity method of accounting. For the three months ended March 31, 2005, TEPPCO had operating revenues of approximately $1,524 million, operating expenses of approximately $1,463 million, operating income of approximately $61 million, income from continuing operations of approximately $46 million, and net income of approximately $47 million.

In July 2005, Duke Energy completed the transfer of a 19.7% interest in DEFS to ConocoPhillips, Duke Energy’s co-equity owner in DEFS, which reduced Duke Energy’s ownership interest in DEFS from 69.7% to 50% and resulted in Duke Energy and ConocoPhillips becoming equal 50% owners of DEFS. As a result of this transaction, Duke Energy deconsolidated its investment in DEFS and subsequently has accounted for the investment using the equity method of accounting (see Note 2). Duke Energy’s 50% of equity in earnings of DEFS for the three and six months ended June 30, 2006 was approximately $149 million and $295 million, respectively, and Duke Energy’s investment in DEFS as of June 30, 2006 was $1,371 million, which is included in Investments in Unconsolidated Affiliates in the accompanying Consolidated Balance Sheets. During the three months ended June 30, 2006, Duke Energy had gas sales to, purchases from, and other operating expenses from affiliates of DEFS of approximately $35 million, $23 million and $7 million, respectively. During the six months ended June 30, 2006, Duke Energy had gas sales to, purchases from, and other operating expenses from affiliates of DEFS of approximately $69 million, $31 million and $15 million, respectively. As of June 30, 2006, Duke Energy had payables to affiliates of DEFS of approximately $50 million. Additionally, Duke Energy received approximately $230 million in distributions of earnings from DEFS in 2006, which are included in Other, assets within Cash Flows from Operating Activities in the accompanying Consolidated Statements of Cash Flows. Duke Energy has recognized an approximate $77 million receivable as of June 30, 2006 due to its share of a distribution declared by DEFS in June 2006 but paid in July 2006. Summary financial information for DEFS, which is accounted for under the equity method, as of and for the three and six months ended June 30, 2006 is as follows:


	Three months Ended June 30, 2006		Six months Ended June 30, 2006
	(in millions)		(in millions)
Operating revenues	$	3,002	$	6,311
Operating expenses	$	2,657	$	5,651
Operating income	$	345	$	660
Net income	$	299	$	590

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	June 30, 2006
	(in millions)
Current assets	$	2,055
Non-current assets	$	4,838
Current liabilities	$	2,098
Non-current liabilities	$	2,040
Minority interest	$	93

DEFS is a limited liability company which is a pass-through entity for U.S. income tax purposes. DEFS also owns corporations who file their own respective, federal, foreign and state income tax returns and income tax expense related to these corporations is included in the income tax expense of DEFS. Therefore, DEFS’ net income does not include income taxes for earnings which are pass-through to the members based upon their ownership percentage and Duke Energy recognizes the tax impacts of its share of DEFS’ pass-through earnings in its income tax expense from continuing operations in the accompanying Consolidated Statements of Operations.

Duke Energy has entered into an agreement to sell 100% of the shares of Westcoast Gas Services, Inc. (WGSI), which owns interests in four gas processing plants and related gas gathering systems, to the Duke Energy Income Fund (Income Fund) for approximately $128 million. The Income Fund is a Canadian income trust that was created in December 2005, and the sale of WGSI reduced Duke Energy’s ownership interest in the Income Fund from approximately 58% to approximately 46%. Closing of the sale is conditional upon approval by the fund unitholders, other than Duke Energy, and its affiliates and is expected to occur during the third quarter of 2006.

Also see Notes 2, 12, 13 and 18 for additional related party information.

20. New Accounting Standards

The following new accounting standards were adopted by Duke Energy subsequent to June 30, 2005 and the impact of such adoption, if applicable, has been presented in the accompanying Consolidated Financial Statements:

Statement of Financial Accounting Standards (SFAS) No. 153, “Exchanges of Nonmonetary Assets—an amendment of APB Opinion No. 29” (SFAS No. 153). In December 2004, the FASB issued SFAS No. 153 which amends APB Opinion No. 29, “Accounting for Nonmonetary Transactions,” by eliminating the exception to the fair-value principle for exchanges of similar productive assets, which were accounted for under APB Opinion No. 29 based on the book value of the asset surrendered with no gain or loss recognition. SFAS No. 153 also eliminates APB Opinion No. 29’s concept of culmination of an earnings process. The amendment requires that an exchange of nonmonetary assets be accounted for at fair value if the exchange has commercial substance and fair value is determinable within reasonable limits. Commercial substance is assessed by comparing the entity’s expected cash flows immediately before and after the exchange. If the difference is significant, the transaction is considered to have commercial substance and should be recognized at fair value. SFAS No. 153 is effective for nonmonetary transactions occurring on or after July 1, 2005. The adoption of SFAS No. 153 did not have a material impact on Duke Energy’s consolidated results of operations, cash flows or financial position.

FASB Interpretation No. 47 “Accounting for Conditional Asset Retirement Obligations ” (FIN 47). In March 2005, the FASB issued FIN 47, which clarifies the accounting for conditional asset retirement obligations as used in SFAS No. 143, “Accounting for Asset Retirement Obligations.” A conditional asset retirement obligation is an unconditional legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the entity. Therefore, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation under SFAS No. 143 if the fair value of the liability can be reasonably estimated. The provisions of FIN 47 were effective for Duke Energy as of December 31, 2005.

FASB Staff Position (FSP) No. APB 18-1, “Accounting by an Investor for Its Proportionate Share of Accumulated Other Comprehensive Income of an Investee Accounted for under the Equity Method in Accordance with APB Opinion No. 18 upon a Loss of Significant Influence” (FSP No. APB 18-1). In July of 2005, the FASB staff issued FSP No. APB 18-1 which provides guidance for how an investor should account for its proportionate share of an investee’s equity adjustments for other comprehensive income (OCI) upon a loss of significant influence. APB Opinion No. 18, “The Equity Method of Accounting for Investments in Common Stock” (APB Opinion No. 18), requires a transaction of an equity method investee of a capital nature be accounted for as if the investee were a consolidated subsidiary, which requires the investor to record its proportionate share of the investee’s adjustments for OCI as increases or decreases to the investment account with corresponding adjustments in equity. FSP No. APB 18-1 requires that an investor’s proportionate share of an

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investee’s equity adjustments for OCI should be offset against the carrying value of the investment at the time significant influence is lost and equity method accounting is no longer appropriate. However, to the extent that the offset results in a carrying value of the investment that is less than zero, an investor should (a) reduce the carrying value of the investment to zero and (b) record the remaining balance in income. The guidance in FSP No. APB 18-1 was effective for Duke Energy beginning October 1, 2005. The adoption of FSP No. APB 18-1 did not have a material impact on Duke Energy’s consolidated results of operations, cash flows or financial position.

SFAS No. 123(R) . “Share-Based Payment.” In December of 2004, the FASB issued SFAS No. 123(R), which replaces SFAS No. 123 and supersedes APB Opinion No. 25. SFAS No. 123(R) requires all share-based payments to employees, including grants of employee stock options, to be recognized in the financial statements based on their fair values. For Duke Energy, timing for implementation of SFAS No. 123(R) was January 1, 2006. The pro forma disclosures previously permitted under SFAS No. 123 are no longer an acceptable alternative. Instead, Duke Energy is required to determine an appropriate expense for stock options and record compensation expense in the Consolidated Statements of Operations for stock options. Duke Energy implemented SFAS No. 123(R) using the modified prospective transition method, which required Duke Energy to record compensation expense for all unvested awards beginning January 1, 2006.

Duke Energy currently also has retirement eligible employees with outstanding share-based payment awards (unvested stock awards, stock based performance awards and phantom stock awards). Compensation cost related to those awards was previously expensed over the stated vesting period or until actual retirement occurred. Effective January 1, 2006, Duke Energy is required to recognize compensation cost for new awards granted to employees over the requisite service period, which generally begins on the date the award is granted through the earlier of the date the award vests or the date the employee becomes retirement eligible. Awards, including stock options, granted to employees that are already retirement eligible will be deemed to have vested immediately upon issuance, and therefore, compensation cost for those awards will be recognized on the date such awards are granted.

SFAS No. 123(R), which was adopted by Duke Energy effective January 1, 2006, is not anticipated to have a material impact on its consolidated results of operations, cash flows or financial position in 2006 based on awards outstanding as of the implementation date. However, the impact to Duke Energy in periods subsequent to adoption of SFAS No. 123(R) will be largely dependent upon the nature of any new share-based compensation awards issued to employees. (See Note 5).

FSP No. FAS 123(R)-4, “Classification of Options and Similar Instruments Issued as Employee Compensation That Allow for Cash Settlement upon the Occurrence of a Contingent Event.” In February 2006, the FASB staff issued FSP No. 123(R)-4 to address the classification of options and similar instruments issued as employee compensation that allow for cash settlement upon the occurrence of a contingent event. The guidance amends SFAS No. 123(R). FSP FAS No. 123(R)-4 provides that cash settlement features that can be exercised only upon the occurrence of a contingent event that is outside the employee’s control does not require classifying the option or similar instrument as a liability until it becomes probable that the event will occur. FSP FAS No. 123(R)-4 applies only to options or similar instruments issued as part of employee compensation arrangements. The guidance in FSP FAS No. 123(R)-4 was effective for Duke Energy as of April 1, 2006. Duke Energy adopted SFAS No. 123(R) as of January 1, 2006 (see Note 5). The adoption of FSP FAS No. FAS 123(R)-4 did not have a material impact on Duke Energy’s consolidated statement of operations, cash flows or financial position.

Staff Accounting Bulletin (SAB) No. 107, “Share-Based Payment” (SAB 107). On March 29, 2005, the Securities and Exchange Commission (SEC) staff issued SAB 107 to express the views of the staff regarding the interaction between SFAS No. 123(R) and certain SEC rules and regulations and to provide the staff’s views regarding the valuation of share-based payment arrangements for public companies. Duke Energy adopted SFAS No. 123(R) and SAB 107 effective January 1, 2006.

FSP No. FAS 115-1 and 124-1, “The Meaning of Other-Than-Temporary Impairment and its Application to Certain Investments.” The FASB issued FSP No. FAS 115-1 and 124-1 in November 2005 which was effective for Duke Energy beginning January 1, 2006. This FSP addresses the determination as to when an investment is considered impaired, whether that impairment is other than temporary, and the measurement of an impairment loss. This FSP also includes accounting considerations subsequent to the recognition of an other-than-temporary impairment and requires certain disclosures about unrealized losses that have not been recognized as other-than-temporary impairments. The guidance in this FSP amends SFAS No. 115, “ Accounting for Certain Investments in Debt and Equity Securities ,” and SFAS No. 124, “ Accounting for Certain Investments Held by Not-for-Profit Organizations ,” and APB Opinion No. 18, “ The Equity Method of Accounting for Investments in Common Stock. ” The adoption of FSP No. FAS 115-1 and 124-1 did not have a material impact on Duke Energy’s consolidated results of operations, cash flows or financial position.

PART I

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

The following new accounting standards have been issued, but have not yet been adopted by Duke Energy as of June 30, 2006:

SFAS No. 155, “Accounting for Certain Hybrid Financial Instruments—an amendment of FASB Statements No. 133 and 140”. In February 2006, the FASB issued SFAS No. 155, which amends SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” and SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities.” SFAS No. 155 allows financial instruments that have embedded derivatives to be accounted for at fair value at acquisition, at issuance, or when a previously recognized financial instrument is subject to a remeasurement (new basis) event, on an instrument-by-instrument basis, in cases in which a derivative would otherwise have to be bifurcated. This Statement is effective for Duke Energy for all financial instruments acquired, issued, or subject to remeasurement after January 1, 2007, and for certain hybrid financial instruments that have been bifurcated prior to the effective date, for which the effect is to be reported as a cumulative-effect adjustment to beginning retained earnings. Duke Energy does not anticipate the adoption of SFAS No. 155 will have any material impact on its consolidated results of operations, cash flows or financial position.

SFAS No. 156, “Accounting for Servicing of Financial Assets—an amendment of FASB Statement No. 140”. In March 2006, the FASB issued SFAS No. 156, which amends SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities.” SFAS No 156 requires recognition of a servicing asset or liability when an entity enters into arrangements to service financial instruments in certain situations. Such servicing assets or servicing liabilities are required to be initially measured at fair value, if practicable. SFAS No. 156 also allows an entity to subsequently measure its servicing assets or servicing liabilities using either an amortization method or a fair value method. This Statement is effective for Duke Energy as of January 1, 2007, and must be applied prospectively, except that where an entity elects to remeasure separately recognized existing arrangements and reclassify certain available-for-sale securities to trading securities, any effects must be reported as a cumulative-effect adjustment to retained earnings. Duke Energy does not anticipate the adoption of SFAS No. 156 will have any material impact on its consolidated results of operations, cash flows or financial position.

FASB Staff Position (FSP) No. FIN 46 (R)-6, “Determining the Variability to Be Considered In Applying FASB Interpretation No. 46(R).” In April 2006, the FASB staff issued FSP No. FIN 46 (R)-6 to address how to determine the variability to be considered in applying FASB Interpretation No. 46(R), “Consolidation of Variable Interest Entities.” The variability that is considered in applying Interpretation 46(R) affects the determination of whether the entity is a variable interest entity (VIE), which interests are variable interests in the entity, and which party, if any, is the primary beneficiary of the VIE. The variability affects the calculation of expected losses and expected residual returns. This guidance will be applied prospectively to all entities with which Duke Energy first becomes involved or existing entities for which a reconsideration event occurs after July 1, 2006. Duke Energy does not anticipate the adoption of FSP No. FIN 46 (R)-6 will have any material impact on its consolidated results of operations, cash flows or financial position.

EITF Issue No. 05-1, “Accounting for the Conversion of an Instrument that Becomes Convertible Upon the Issuer’s Exercise of a Call Option.” (EITF 05-1). In June 2006, the EITF reached a consensus on Issue No. 05-1. The consensus requires that the issuance of equity securities to settle a debt instrument (pursuant to the instrument’s original conversion terms) that became convertible upon the issuer’s exercise of a call option be accounted for as a conversion if the debt instrument contained a substantive conversion feature as of its issuance date. If the debt instrument did not contain a substantive conversion option as of its issuance date, the issuance of equity securities to settle the debt instrument should be accounted for as a debt extinguishment. The consensus is effective for Duke Energy for all conversions within its scope that result from the exercise of call options beginning July 1, 2006. Duke Energy does not anticipate the adoption of EITF Issue 05-1 will have any material impact on its consolidated results of operations, cash flows or financial position.

EITF Issue No. 06-3, “How Taxes Collected from Customers and Remitted to Governmental Authorities Should Be Presented in the Income Statement (That Is, Gross versus Net Presentation)” (EITF 06-3). In June 2006, the EITF reached a consensus on Issue No. 06-3 to address any tax assessed by a governmental authority that is directly imposed on a revenue-producing transaction between a seller and a customer and may include, but are not limited to, sales, use, value added, and some excise taxes. For taxes within the issue’s scope, the consensus requires that entities present such taxes on either a gross (i.e., include in revenues and costs) or net (i.e., exclude from revenues) basis according to their accounting policies, which should be disclosed. If such taxes are reported gross and are significant, entities should disclose the amounts of those taxes. Disclosures may be made on an aggregate basis. The consensus is effective for Duke Energy beginning January 1, 2007. Duke Energy does not anticipate the adoption of EITF Issue 06-3 will have any material impact on its consolidated results of operations.

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DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes—an interpretation of FASB Statement No. 109” (FIN No. 48) . On July 13, 2006, the FASB issued FIN No. 48, which interprets SFAS No. 109, “Accounting for Income Taxes.” FIN No. 48 provides guidance for the recognition, measurement, classification and disclosure of the financial statement effects of a position taken or expected to be taken in a tax return (“tax position”). The financial statement effects of a tax position must be recognized when there is a likelihood of more than 50 percent that based on the technical merits, the position will be sustained upon examination and resolution of the related appeals or litigation processes, if any. A tax position that meets the recognition threshold must be measured initially and subsequently as the largest amount of tax benefit that is greater than 50 percent likely of being realized upon ultimate settlement with a taxing authority. The Interpretation is effective for fiscal years beginning after December 15, 2006. Duke Energy is currently evaluating the impact of adopting FIN No. 48, and cannot currently estimate the impact of FIN No. 48 on its consolidated results of operations, cash flows or financial position.

21. Income Tax Expense

Although the outcome of tax audits is uncertain, management believes that adequate provisions for income and other taxes, such as sales and use, franchise, and property, have been made for potential liabilities resulting from such matters. As of June 30, 2006, Duke Energy has total provisions of approximately $215 million for uncertain tax positions, as compared to approximately $150 million as of December 31, 2005, including interest. The increase in total provisions from year end is primarily attributable to the merger with Cinergy. Management is not aware of any issues for open tax years that upon final resolution are expected to have a material adverse effect on Duke Energy’s consolidated results of operations, cash flows or financial position.

The effective tax rate for the three months ended June 30, 2006 was approximately 28.7% as compared to the effective tax rate of 32.4% for the same period in 2005. The effective tax rate for the six months ended June 30, 2006 was approximately 32.0% as compared to the effective tax rate of 33.9% for the same period in 2005. The decrease in the effective tax rates for both periods was primarily attributable to reductions in state deferred tax liabilities related to the merger with Cinergy.

22. Subsequent Events

PART I

Item 2. Management’s Discussion and Analysis of Results of Operations and Financial Condition.

INTRODUCTION

Management’s Discussion and Analysis should be read in conjunction with the Consolidated Financial Statements.

Executive Overview

In 2006, management of Duke Energy established a goal to achieve a business model that would give both Duke Energy’s electric and gas businesses stand-alone strength and additional scope and scale along with steady and stable earnings growth. So far in 2006, management has executed this strategy primarily through strategically completed and pending acquisitions, as well as dispositions of certain businesses with higher risk profiles.

On April 3, 2006, Duke Energy and Cinergy consummated the previously announced merger, which combines the Duke Energy and Cinergy regulated franchises as well as deregulated generation in the Midwestern United States. The merger with Cinergy increased the size and scope of Duke Energy’s electric utility operations. Duke Energy management expects to achieve numerous synergies, both immediately and over time, in all regions impacted by the merger.

In line with giving the electric utility operations more scope and scale, Duke Energy has announced an agreement with Southern Company to evaluate the potential construction of a new nuclear power plant at a site jointly owned in Cherokee County, South Carolina. Additionally, Duke Energy continues to evaluate other opportunities to re-invest in the electric utility operations, by modernizing and expanding older coal-fired plants in the Carolinas and exploring the replacement of an aging coal plant in Indiana with a coal gasification plant. Duke Energy has also announced an agreement to acquire from Dynegy an approximate 825 megawatt power plant located in Rockingham County, North Carolina. The transaction requires various approvals and is anticipated to close by year-end 2006. This peaking plant, which will primarily be used during times of high electricity demand, generally in the winter and summer months, will provide customers with competitively priced peaking capacity and helps to ensure Duke Energy can meet growing customer demands for electricity in the foreseeable future.

As a result of the additional size and scope of the electric utility operations discussed above, in June 2006, the Board of Directors of Duke Energy authorized management to pursue a plan to create two separate publicly traded companies by spinning off Duke Energy’s Natural Gas Transmission business segment to Duke Energy shareholders. The new natural gas company, which has yet to be named, would principally consist of Duke Energy’s Natural Gas Transmission business segment, which would include Union Gas, and would also include Duke Energy’s 50-percent ownership interest in Duke Energy Field Services, LLC (DEFS). If completed, the decision to spin off the natural gas business is expected to deliver long-term value to shareholders as the stand-alone companies will be able to more easily participate in growth opportunities in their own industries as well as the gas and power industry consolidations. Approximately $3 billion of debt currently at Duke Capital LLC (Duke Capital) is anticipated to transfer to the new natural gas company at the time of the spin-off. Duke Energy is targeting a January 1, 2007 effective date for the transaction and the results of the natural gas business are expected to be treated as discontinued operations in the period the spin-off is consummated.

The businesses remaining in Duke Energy post-spin are anticipated to be the U.S. Franchised Electric and Gas business segment, the Commercial Power business segment, the International Energy business segment and Crescent Resources, LLC (Crescent).

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In connection with the effort to reduce the risk profile of Duke Energy and to focus on businesses that can be expected to contribute steady, stable earnings growth, during 2006 Duke Energy has finalized the sale of the former Duke Energy North America (DENA) power generation fleet outside of the Midwest to LS Power Equity Partners (LS Power) and has agreed to sell the Cinergy commercial marketing and trading business to Fortis, a Benelux-based financial services group (Fortis). The sale to Fortis is subject to various approvals and is anticipated to close in the third quarter of 2006.

Additionally, the Board of Directors of Duke Energy has authorized management to explore the potential value of bringing in a joint venture partner at Crescent to expand the business and create a platform for increased growth.

Effective with the third quarter 2006, the Board of Directors of Duke Energy has approved a quarterly dividend increase of $0.01 per share, increasing the annual dividend to $1.28 per share. Additionally, during 2006 Duke Energy has repurchased approximately 17.5 million shares of its common stock for approximately $500 million. In connection with the above mentioned plan to spin off Duke Energy’s natural gas business to Duke Energy shareholders, the share repurchase program has been suspended.

For the three months ended June 30, 2006, Duke Energy reported net income of $355 million and diluted earnings per share of $0.28 as compared to net income and diluted earnings per share of $309 million and $0.32, respectively, for the three months ended June 30, 2005. The decrease in earnings per share was due primarily to the increase in number of shares outstanding, primarily as a result of the issuance of shares in connection with the Cinergy merger and conversions of debt to equity, offset by the repurchase of shares under the share repurchase program, during the second quarter of 2006 (see Note 2 to the Consolidated Financial Statements, “Earnings Per Share”). These results include the impacts of former Cinergy for the quarter ended June 30, 2006. For the six months ended June 30, 2006, Duke Energy reported net income of $713 million and diluted earnings per share of $0.64 as compared to net income and diluted earnings per share of $1,177 million and $1.20, respectively, for the six months ended June 30, 2005. These amounts include the results of former Cinergy for the quarter ended June 30, 2006. The decrease in net income and earnings per share was due primarily to the pre-tax gain of approximately $900 million (net of minority interest of approximately $343 million) recorded in 2005 related to DEFS’ sale of Texas Eastern Products Pipeline Company, LLC (TEPPCO GP), which is the general partner of TEPPCO Partners, LP (TEPPCO LP), and Duke Energy’s sale of its limited partner interests in TEPPCO LP and the recognition of prior year hedge losses. In addition to the impact of lower net income for the first six months of 2006 as compared to the same period in 2005, the decrease in earnings per share for this period was partially attributable to the increase in number of shares outstanding, as discussed above. The highlights for the three and six months ended June 30, 2006 include:

•

U.S. Franchised Electric and Gas, which is comprised of Duke Energy Carolinas (formerly known as Duke Power) and the regulated portion of the legacy Cinergy utilities located in the Midwest, delivered higher results for the three and six months ended June 30, 2006 as compared to the same periods in the prior year, primarily due to the inclusion of legacy Cinergy for the second quarter ended June 30, 2006, improved weather in the Duke Energy Carolinas region and customer growth in the service territories, partially offset by lower wholesale power revenues, rate credits and contributions as a result of stipulations to merger approval and an approximate $18 million charge related to a North Carolina Utility Commission (NCUC) order that changed the methodology for calculating BPM profit sharing;

•

Natural Gas Transmission’s earnings increased over the same periods in the previous year due to higher natural gas processing—primarily from the addition of the Empress assets acquired in 2005, business expansion, favorable resolution of property tax issues and the impact of a strengthening Canadian currency. These results were partially offset by higher operating costs and lower equity earnings related to interest expense;

•

Field Services results decreased in 2006 as compared to the same periods in the prior year, primarily as a result of the gain from the sale of TEPPCO in 2005, the reduction in ownership percentage by Duke Energy as a result of the DEFS disposition transaction whereby Duke Energy reduced its ownership interest in DEFS from 69.7% to 50% effective July 1, 2005, and decreased volumes, partially offset by strong commodity prices during 2006, natural gas liquids (NGL) and gas marketing results and lower hedge losses recognized with the discontinuance of certain cash flow hedges in 2005;

•

Commercial Power, which consists of non-regulated generation and marketing in the Midwest and Duke Energy Generation Services, including DENA’s Midwest power generating assets, reported improved results over the same periods in the prior year. Improved results were primarily driven by the addition of Cinergy’s non-regulated businesses in the Midwest and improved results from DENA’s power generation assets in the region. Results were partially offset by approximately $48 million in purchase accounting adjustments recorded during second quarter 2006, a lack of tax credits associated with Cinergy’s synfuel facilities and operating costs associated with Cinergy’s synfuel facilities;

•

International Energy experienced lower earnings compared to the same periods in the prior year primarily driven by an impairment of the Campeche equity investment in Mexico and related note receivable reserve, increased power purchases as a result of an

PART I

unplanned outage in Peru and unfavorable hydrology in Peru and Brazil. These results were partially offset by favorable currency impacts—mainly in Brazil;

•

Crescent had improved results compared to same periods in the prior year, driven primarily by an approximate $81 million gain on the sale of properties at Potomac Yard in Washington, DC, and an approximate $52 million land sale at Lake Keowee in South Carolina during 2006;

•

Other losses increased for the three months ended June 30, 2006 compared to the same period in the prior year due primarily to charges in 2006 associated with the Cinergy merger, partially offset by a reduction in charges for liabilities associated with mutual insurance companies. For the six months ended June 30, 2006, Other losses decreased for the six months ended June 30, 2006 compared to the same period in the prior year primarily as a result of a reduction in charges for liabilities associated with mutual insurance companies and lower losses on Field Services hedges, partially offset by Cinergy merger related costs; and

•

Loss from discontinued operations, primarily related to the exit of the DENA business, increased in 2006 compared to the same periods in the prior year due primarily to the termination or sale of the final remaining contracts at DENA. Additionally, in the second quarter of 2006, an exit plan for the Cinergy commercial marketing and trading business was announced and 2006 results reflects this portion of the business as discontinued operations subsequent to the date of acquisition.

RESULTS OF OPERATIONS

Results of Operations and Variances


	Three Months Ended June 30,									Six Months Ended June 30,
	2006			2005			Increase (Decrease)			2006			2005			Increase (Decrease)
	(in millions)
Operating revenues	$	3,973		$	5,274		$	(1,301	)	$	7,174		$	10,602		$	(3,428	)
Operating expenses		3,363			4,508			(1,145	)		5,801			9,170			(3,369	)
Gains on sales of investments in commercial and multi-family real estate		145			12			133			171			54			117
(Losses) gains on sales of other assets and other, net		(11	)		—			(11	)		22			9			13

Operating income		744			778			(34	)		1,566			1,495			71
Other income and expenses, net		220			80			140			407			1,384			(977	)
Interest expense		339			295			44			589			585			4
Minority interest expense		15			78			(63	)		30			498			(468	)

Earnings from continuing operations before income taxes		610			485			125			1,354			1,796			(442	)
Income tax expense from continuing operations		175			157			18			433			608			(175	)

Income from continuing operations		435			328			107			921			1,188			(267	)
Loss from discontinued operations, net of tax		(80	)		(19	)		(61	)		(208	)		(11	)		(197	)

Net income		355			309			46			713			1,177			(464	)
Dividends and premiums on redemption of preferred and preference stock		—			2			(2	)		—			4			(4	)

Earnings available for common stockholders	$	355		$	307		$	48		$	713		$	1,173		$	(460	)

Consolidated Operating Revenues

Three Months Ended June 30, 2006 as Compared to June 30, 2005. Consolidated operating revenues for the three months ended June 30, 2006 decreased $1,301 million, compared to the same period in 2005. This change was driven primarily by:

•

A $2,872 million decrease due to the deconsolidation of DEFS, effective July 1, 2005

Partially offsetting this decrease in revenues were:

•

An approximate $1,266 million increase due to the merger with Cinergy

•

A $215 million increase at Natural Gas Transmission due to new Canadian assets, primarily higher processing revenues on the Empress System (approximately $122 million), favorable Canadian dollar foreign exchange impacts (approximately $47 million),

PART I

recovery of higher natural gas commodity costs (approximately $27 million), resulting from higher natural gas prices passed through to customers without a mark-up at Union Gas Limited (Union Gas), partially offset by lower gas usage due to unseasonably warmer weather (approximately $19 million), and

•

A $68 million increase at International Energy due to increased ownership and resulting consolidation of Aguaytia (approximately $28 million), higher energy prices and generation in Latin America (approximately $25 million) and an increase in Brazil mainly due to favorable exchange rates and higher average prices (approximately $11 million).

Six Months Ended June 30, 2006 as Compared to June 30, 2005. Consolidated operating revenues for the six months ended June 30, 2006 decreased $3,428 million, compared to the same period in 2005. This change was driven primarily by:

•

A $5,530 million decrease due to the deconsolidation of DEFS, effective July 1, 2005

Partially offsetting this decrease in revenues were:

•

An approximate $1,266 million increase due to the merger with Cinergy

•

A $498 million increase at Natural Gas Transmission due to new Canadian assets, primarily higher processing revenues on the Empress System (approximately $267 million), recovery of higher natural gas commodity costs (approximately $145 million), resulting from higher natural gas prices passed through to customers without a mark-up at Union Gas, and favorable Canadian dollar foreign exchange impacts (approximately $102 million), partially offset by lower gas usage due to unseasonably warmer weather (approximately $104 million)

•

A $131 million increase at International Energy due to higher energy prices and favorable exchange rates in Latin America (approximately $79 million) and increased ownership and resulting consolidation of Aguaytia (approximately $48 million), and

•

An approximate $130 million increase in Other related to the prior year impact of the realized and unrealized mark-to-market losses of Field Services’ hedges that had been recorded in operating revenues prior to the deconsolidation of DEFS.

For a more detailed discussion of operating revenues, see the segment discussions that follow.

Consolidated Operating Expenses

Three Months Ended June 30, 2006 as Compared to June 30, 2005. Consolidated operating expenses for the three months ended June 30, 2006 decreased $1,145 million, compared to the same period in 2005. This change was driven primarily by:

•

A $2,636 million decrease due to the deconsolidation of DEFS, effective July 1, 2005

Partially offsetting this decrease in expenses were:

•

An approximate $1,152 million increase due to the merger with Cinergy

•

A $152 million increase at Natural Gas Transmission due to new Canadian assets, primarily the Empress System (approximately $91 million), Canadian dollar foreign exchange impacts (approximately $37 million) and increased natural gas prices at Union Gas (approximately $27 million), partially offset by lower gas usage due to unseasonably warmer weather (approximately $15 million), and

•

A $106 million increase at International Energy primarily due to a reserve on a note receivable from the Campeche equity investment (approximately $38 million) (see Note 12 to the Consolidated Financial Statements, “Impairments and Other Charges”), increased ownership and resulting consolidation of Aguaytia (approximately $31 million), and higher fuel prices and volumes in Latin America due to increased generation (approximately $17 million).

•

A $74 million increase associated with costs to achieve the Cinergy merger.

Six Months Ended June 30, 2006 as Compared to June 30, 2005. Consolidated operating expenses for the six months ended June 30, 2006 decreased $3,369 million, compared to the same period in 2005. This change was driven primarily by:

•

A $5,207 million decrease due to the deconsolidation of DEFS, effective July 1, 2005

Partially offsetting this decrease in expenses were:

•

An approximate $1,152 million increase due to the merger with Cinergy

•

A $431 million increase at Natural Gas Transmission due to new Canadian assets, primarily the Empress System (approximately $222 million), increased natural gas prices at Union Gas (approximately $145 million), resulting from high natural gas prices passed through to customers without a mark-up at Union Gas, Canadian dollar foreign exchange impacts (approximately $81 million), partially offset by lower gas purchase costs due to unseasonably warmer weather (approximately $82 million), and

PART I

•

A $144 million increase at International Energy primarily due to increased ownership and resulting consolidation of Aguaytia (approximately $44 million), a reserve on a note receivable from the Campeche equity investment (approximately $38 million), and higher fuel prices and volumes in Latin America due to increased generation (approximately $35 million).

•

A $78 million increased associated with costs to achieve the Cinergy merger.

For a more detailed discussion of operating expenses, see the segment discussions that follow.

Consolidated Gains on Sales of Investments in Commercial and Multi-Family Real Estate

Three Months Ended June 30, 2006 as Compared to June 30, 2005. Consolidated gains on sales of investments in commercial and multi-family real estate increased $133 million compared to the same period in 2005. This increase was primarily due to an approximate $81 million gain on the sale of two office buildings at Potomac Yard in Washington, D.C. and an approximate $52 million gain on a land sale at Lake Keowee in northwestern South Carolina.

Six Months Ended June 30, 2006 as Compared to June 30, 2005. Consolidated gains on sales of investments in commercial and multi-family real estate increased $117 million compared to the same period in 2005. This increase was primarily due to an approximate $81 million gain on the sale of two office buildings at Potomac Yard in Washington, D.C. and an approximate $52 million gain on a land sale at Lake Keowee in northwestern South Carolina.

Consolidated (Losses) Gains on Sales of Other Assets and Other, Net

Six Months Ended June 30, 2006 as Compared to June 30, 2005. Consolidated (losses) gains on sales of other assets and other, net for the six months ended June 30, 2006 increased $13 million, compared to the same period in 2005. The increase was due primarily to an approximate $23 million gain on the settlement of a customer’s transportation contract at Natural Gas Transmission in 2006, partially offset by an approximate $5 million loss on a contract termination.

Consolidated Operating Income

Three Months Ended June 30, 2006 as Compared to June 30, 2005. Consolidated operating income for the three months ended June 30, 2006 decreased $34 million, compared to the same period in 2005. Decreased operating income was primarily related to impacts of the deconsolidation of DEFS, effective July 1, 2005, which amounted to $235 million for the three months ended June 30, 2005, partially offset by approximately $100 million of operating income in the three months ended June 30, 2006 generated by legacy Cinergy as a result of the merger. Other drivers to operating income are discussed above.

Six Months Ended June 30, 2006 as Compared to June 30, 2005. Consolidated operating income for the six months ended June 30, 2006 increased $71 million, compared to the same period in 2005. Increased operating income was primarily related to approximately $100 million of operating income generated by legacy Cinergy as a result of the merger and an approximate $250 million negative impact to operating income during the six months ended June 30, 2005 related to the discontinuance of certain cash flow hedges entered into to hedge Field Services’ commodity price risk. Partially offsetting those results were the impacts of the deconsolidation of DEFS, effective July 1, 2005, which amounted to $322 million for the six months ended June 30, 2005. Other drivers to operating income are discussed above.

For more detailed discussions, see the segment discussions that follow.

Consolidated Other Income and Expenses, net

Three Months Ended June 30, 2006 as Compared to June 30, 2005. Consolidated other income and expenses, net for the three months ended June 30, 2006 increased $140 million, compared to the same period in 2005. The increase was due primarily to an increase of approximately $155 million in equity in earnings of unconsolidated affiliates primarily due to the deconsolidation of DEFS starting July 1, 2005, partially offset by approximately $20 million of impairment charges on equity method investments recorded in the second quarter 2006, primarily International Energy’s investment in Campeche (see Note 12 to the Consolidated Financial Statements, “Impairments and Other Charges”).

Six Months Ended June 30, 2006 as Compared to June 30, 2005. Consolidated other income and expenses, net for the six months ended June 30, 2006 decreased $977 million, compared to the same period in 2005. The decrease was due primarily to the $1,245 million pre-tax gains on sales of equity investments recorded in 2005, primarily associated with the sale of TEPPCO GP and Duke Energy’s limited partner interest in TEPPCO LP, as discussed above, partially offset by an increase of approximately $289 million in equity in earnings of unconsolidated affiliates primarily due to the deconsolidation of DEFS starting July 1, 2005.

PART I

Consolidated Interest Expense

Three Months Ended June 30, 2006 as Compared to June 30, 2005. Consolidated interest expense for the three months ended June 30, 2006 increased $44 million, compared to the same period in 2005. This increase is primarily attributable to the increase in long-term debt as a result of the merger with Cinergy, partially offset by the deconsolidation of DEFS.

Six Months Ended June 30, 2006 as Compared to June 30, 2005. Consolidated interest expense for the six months ended June 30, 2006 remained relatively flat, increasing $4 million, compared to the same period in 2005. Although consolidated interest expense remained relatively flat, interest expense in 2006 was impacted by the increase in long-term debt as a result of the merger with Cinergy, which was offset by reduced interest expense associated with DEFS, which was deconsolidated on July 1, 2005. Interest expense in 2005 reflected amounts related to debt associated with DEFS prior to the deconsolidation on July 1, 2005.

Consolidated Minority Interest Expense

Three Months Ended June 30, 2006 as Compared to June 30, 2005. Consolidated minority interest expense for the three months ended June 30, 2006 decreased $63 million, compared to the same period in 2005. The decrease primarily resulted from the impact of deconsolidation of DEFS, as discussed above.

Six Months Ended June 30, 2006 as Compared to June 30, 2005. Consolidated minority interest expense for the six months ended June 30, 2006 decreased $468 million, compared to the same period in 2005. The decrease primarily resulted from the 2005 gain associated with the sale of TEPPCO GP and the impact of deconsolidation of DEFS, as discussed above.

Consolidated Income Tax Expense from Continuing Operations

Three Months Ended June 30, 2006 as Compared to June 30, 2005. Consolidated income tax expense from continuing operations for the three months ended June 30, 2006 increased $18 million, compared to the same period in 2005. The increase primarily resulted from higher pre-tax earnings. The effective tax rate decreased in the three months ended June 30, 2006 (28.7%) compared to the same period in 2005 (32.4%), primarily due to reductions in state deferred tax liabilities related to the merger with Cinergy.

Six Months Ended June 30, 2006 as Compared to June 30, 2005. Consolidated income tax expense from continuing operations for the six months ended June 30, 2006 decreased $175 million, compared to the same period in 2005. This decrease primarily resulted from lower pre-tax earnings, due primarily to the 2005 gains associated with the sale of TEPPCO GP and Duke Energy’s limited partner interest in TEPPCO LP as discussed above. The effective tax rate decreased in the six months ended June 30, 2006 (32.0%) compared to the same period in 2005 (33.9%), primarily due to reductions in state deferred tax liabilities related to the merger with Cinergy.

Consolidated Loss from Discontinued Operations, net of tax

Three Months Ended June 30, 2006 as Compared to June 30, 2005. Consolidated loss from discontinued operations, net of tax for the three months ended June 30, 2006 increased $61 million, compared to the same period in 2005. This increase primarily resulted from an approximate $61 million increase in after-tax loss at DENA associated with certain contract terminations or sales, an approximate $6 million after-tax loss associated with the exiting of the Cinergy commercial marketing and trading operations, partially offset by an approximate $5 million increase in after-tax gain at International Energy due primarily to a write-up of a receivable from Norsk Hydro (see Note 13 to the Consolidated Financial Statements, “Discontinued Operations and Assets Held for Sale”).

Six Months Ended June 30, 2006 as Compared to June 30, 2005. Consolidated loss from discontinued operations, net of tax for the six months ended June 30, 2006 increased $197 million, compared to the same period in 2005. This increase primarily resulted from an approximate $184 million increase in after-tax loss at DENA associated with certain contract terminations or sales, an approximate $6 million after-tax loss associated with exiting the Cinergy commercial marketing and trading operations and an approximate $13 million increase in after-tax loss at International Energy primarily as a result of the recording of an allowance against a receivable, offset by the $5 million after-tax write-up as mentioned above.

Segment Results

Management evaluates segment performance based on earnings before interest and taxes from continuing operations, after deducting minority interest expense related to those profits (EBIT). On a segment basis, EBIT excludes discontinued operations, represents all profits from continuing operations (both operating and non-operating) before deducting interest and taxes, and is net of the minority interest expense related to those profits. Cash, cash equivalents and short-term investments are managed centrally by Duke Energy, so the gains and losses on foreign currency remeasurement, and interest and dividend income on those balances, are excluded from the

PART I

segments’ EBIT. Management considers segment EBIT to be a good indicator of each segment’s operating performance from its continuing operations, as it represents the results of Duke Energy’s ownership interest in operations without regard to financing methods or capital structures.

Duke Energy’s segment EBIT may not be comparable to a similarly titled measure of another company because other entities may not calculate EBIT in the same manner. Segment EBIT is summarized in the following table, and detailed discussions follow.

See Note 14 to the Consolidated Financial Statements, “Business Segments,” for a discussion of Duke Energy’s new segment structure. Additionally, the results of operations and segment assets for DENA Midwestern operations are included in the Commercial Power segment, whereby previously DENA’s Midwestern operations were included in Other.

EBIT by Business Segment


	Three Months Ended June 30,						Six Months Ended June 30,
	2006			2005			2006			2005
	(in millions)
U.S. Franchised Electric and Gas	$	351		$	274		$	710		$	610
Natural Gas Transmission		361			304			799			715
Field Services ^(a)		148			164			292			1,083
Commercial Power		20			(16	)		(7	)		(34	)
International Energy		26			86			113			154
Crescent		174			38			216			90

Total reportable segment EBIT		1,080			850			2,123			2,618
Other		(174	)		(102	)		(232	)		(286	)

Total reportable segment and other EBIT		906			748			1,891			2,332
Interest expense		(339	)		(295	)		(589	)		(585	)
Interest income and other ^(b)		43			32			52			49

Consolidated earnings from continuing operations before income taxes	$	610		$	485		$	1,354		$	1,796

(a)

In July 2005, Duke Energy completed the previously announced agreement with ConocoPhillips to reduce Duke Energy’s ownership interest in DEFS from 69.7% to 50%. Field Services segment data includes DEFS as a consolidated entity for the three and six month periods ended June 30, 2005 and as an equity method investment for the three and six months ended June 30, 2006.

(b)	Includes interest income, foreign currency transaction gains and losses, additional minority interest expense not allocated to the segment results and intersegment eliminations.

The amounts discussed below include intercompany transactions that are eliminated in the Consolidated Financial Statements.

US Franchised Electric and Gas


	Three Months Ended June 30,								Six Months Ended June 30,
	2006		2005			Increase (Decrease)			2006		2005		Increase (Decrease)
	(in millions, except where noted)
Operating revenues	$	2,130	$	1,234		$	896		$	3,422	$	2,499	$	923
Operating expenses		1,791		959			832			2,729		1,890		839
Gains on sales of other assets and other, net		2		—			2			2		1		1

Operating income		341		275			66			695		610		85
Other income and expenses, net		10		(1	)		11			15		—		15

EBIT	$	351	$	274		$	77		$	710	$	610	$	100

Duke Energy Carolinas GWh sales ^(a)		19,944		20,431			(487	)		40,524		41,594		(1,070	)
Duke Energy Midwest GWh sales ^(a)(b)		14,803		—			14,803			14,803		—		14,803

(a)	Gigawatt-hours (GWh)

(b)	Relates to operations of former Cinergy

PART I

The following table shows the changes in GWh sales and average number of customers for Duke Energy Carolinas. The table below excludes amounts related to former Cinergy since results of operations of Cinergy are only included from the date of acquisition and thereafter.


Increase (decrease) over prior year	Three Months Ended		Six Months Ended
Residential sales ^(a)	4.5	%	(0.7	)%
General service sales ^(a)	4.1	%	1.5	%
Industrial sales ^(a)	(0.8	)%	(2.1	)%
Wholesale sales	(50.7	)%	(28.4	)%
Total DE Carolinas sales ^(b)	(2.4	)%	(2.6	)%
Average number of customers	2.1	%	1.9	%

(a)	Major components of DE Carolinas’ retail sales

(b)	Consists of all components of DE Carolinas’ sales, including retail sales, and wholesale sales to incorporated municipalities and to public and private utilities and power marketers.

Three Months Ended June 30, 2006 as Compared to June 30, 2005

Operating Revenues. The increase was driven primarily by:

•

A $848 million increase in regulated operating revenues due to the merger with Cinergy

•

A $52 million increase in fuel revenues driven by increased fuel rates for retail customers due primarily to increased coal costs and increased GWh sales to retail customers. Sales to residential and commercial customers increased by approximately 4%, resulting in more fuel revenue collections from those customers. The delivered cost of coal in 2006 is approximately $7 per ton higher than the same period in 2005, representing a 12% increase

•

A $29 million increase related to GWh sales to retail customers due to more favorable weather conditions during the quarter than compared to the same period in 2005. Weather statistics for cooling degree days were approximately 1% below normal in second quarter 2006 compared to 24% below normal during the same period in 2005, partially offset by

•

A $37 million decrease in wholesale power revenues. While prices were favorable, sales volumes decreased by approximately 51% partly due to production constraints caused by generation outages. In addition to lower wholesale sales volumes, the lower results reflected an $18 million charge due to an order issued by the NCUC in 2006 to change the method for calculating wholesale profits and related sharing. This order was retroactive to January 1, 2005, and, therefore, $11 million of the recorded charge related to wholesale sales in 2005.

Operating Expenses. The increase was driven primarily by:

•

A $786 million increase in regulated operating expenses due to the merger with Cinergy

•

A $48 million increase in fuel expenses due primarily to higher coal costs. Fossil generation fueled by coal accounted for slightly more than 50% of total generation during the second quarter for both 2006 and 2005 and the delivered cost of coal is approximately $7 per ton higher than the same period in 2005, and

•

A $9 million increase in donations, primarily due to a one time $12 million donation, ordered by the NCUC as a condition of the Cinergy merger, to help support various low income, environmental, economic development and educationally beneficial programs in North Carolina.

Other Income and expenses, net. The increase was driven primarily by the addition of Cinergy and a $6 million increase in the allowance for funds used during construction (AFUDC), due primarily to on-going construction projects in the Carolinas.

EBIT . The increase in EBIT resulted primarily from the acquisition of the regulated operations of Cinergy and more favorable weather conditions in the Carolinas in comparison to the same period in 2005. These changes were partially offset by decreased Carolinas’ sales to wholesale customers due to limited market opportunities and the NCUC order changing the calculation of wholesale profits.

Six Months Ended June 30, 2006 as Compared to June 30, 2005

Operating Revenues. The increase was driven primarily by:

•

A $848 million increase in regulated operating revenues due to the merger with Cinergy

•

A $77 million increase in fuel revenues driven by increased fuel rates for retail customers due primarily to increased coal costs. The delivered cost of coal in 2006 is approximately $9 per ton higher than the same period in 2005, representing a 15% increase

PART I

•

An $18 million increase related to demand from retail customers, due primarily to continued growth in the number of residential and general service customers in the DE Carolinas’ service territory. The number of customers in 2006 has increased by approximately 43,000 compared to the same period in 2005, partially offset by

•

A $25 million decrease in wholesale power revenues. While prices were favorable, sales volumes decreased by approximately 30% partly due to production constraints caused by generation outages. In addition to lower wholesale sales volumes, the lower results reflected an $18 million charge due to an order issued by the NCUC in 2006 to change the method for calculating wholesale profits and related sharing. This order was retroactive to January 1, 2005, and, therefore, $11 million of the recorded charge related to wholesale sales in 2005. For the six months ended June 30, 2006, the sharing of profits was $31 million while for the same period in 2005, the sharing of profits was $22 million.

Operating Expenses. The increase was driven primarily by:

•

A $786 million increase in regulated operating expenses due to the merger with Cinergy

•

An $80 million increase in fuel expenses, due primarily to higher coal costs. Fossil generation fueled by coal accounted for slightly more than 50% of total generation during the second quarter for both 2006 and 2005 and the delivered cost of coal is approximately $9 per ton higher than the same period in 2005

•

A $31 million decrease in Duke Energy Carolinas regulatory amortization, due to reduced amortization of compliance costs related to clean air legislation during 2006 as compared to the same period in 2005.

Other Income and expenses, net. The increase was driven primarily by an $11 million increase in AFUDC, due primarily to on-going construction projects in the Carolinas and the acquisition of Cinergy.

EBIT . The increase in EBIT resulted primarily from the acquisition of the regulated operations of Cinergy, increased demand by Carolina retail customers and reduced regulatory amortization in the Carolinas. This increase was partially offset by lower wholesale power sales in the Carolinas.

Natural Gas Transmission


	Three Months Ended June 30,							Six Months Ended June 30,
	2006		2005		Increase (Decrease)			2006		2005		Increase (Decrease)
	(in millions, except where noted)
Operating revenues	$	979	$	764	$	215		$	2,453	$	1,955	$	498
Operating expenses		622		470		152			1,690		1,259		431
Gains on sales of other assets and other, net		—		1		(1	)		29		3		26

Operating income		357		295		62			792		699		93
Other income and expenses, net		15		15		—			27		31		(4	)
Minority interest expense		11		6		5			20		15		5

EBIT	$	361	$	304	$	57		$	799	$	715	$	84

Proportional throughput, TBtu ^(a)		706		719		(13	)		1,669		1,775		(106	)

(a)	Trillion British thermal units. Revenues are not significantly impacted by pipeline throughput fluctuations since revenues are primarily composed of demand charges.

Three Months Ended June 30, 2006 as Compared to June 30, 2005

Operating Revenues. The increase was driven primarily by:

•

A $122 million increase due to new Canadian assets, primarily higher processing revenues on the Empress System as a result of commodity prices.

PART I

•

A $47 million increase due to foreign exchange rates favorably impacting revenues from the Canadian operations as a result of the strengthening Canadian dollar (partially offset by currency impacts to expenses).

•

A $27 million increase from recovery of higher natural gas commodity costs, resulting from higher natural gas prices passed through to customers without a mark-up at Union. This revenue increase is offset in expenses, and

•

A $9 million increase from completed and operational pipeline expansion projects in the United States, partially offset by

•

A $19 million decrease in gas distribution revenues at Union Gas primarily resulting from lower gas usage due to unseasonably warmer weather.

Operating Expenses. The increase was driven primarily by:

•

A $91 million increase due to new Canadian assets, primarily gas purchase cost associated with the Empress System.

•

A $37 million increase caused by foreign exchange impacts (offset by currency impacts to revenues, as discussed above).

•

A $27 million increase related to increased natural gas prices at Union Gas. This amount is offset in revenues.

•

A $15 million increase in U.S. O&M primarily related to higher insurance premiums, pipeline integrity costs, and other increased transmission and storage operation expenses, partially offset by

•

A $15 million decrease related to the resolution of prior tax years’ ad valorem tax, and

•

A $15 million decrease in gas purchase costs, primarily resulting from lower gas usage due to unseasonably warmer weather.

EBIT . The increase in EBIT is due primarily to the increase in processing earnings (Empress System), U.S. business expansion and operations, the strengthening Canadian currency, and the reversal of accruals for ad valorem taxes, partially offset by increased U.S. O&M expenses.

Six Months Ended June 30, 2006 as Compared to June 30, 2005

Operating Revenues. The increase was driven primarily by:

•

A $267 million increase due to new Canadian assets, primarily higher processing revenues on the Empress System as a result of commodity prices.

•

A $145 million increase from recovery of higher natural gas commodity costs, resulting from higher natural gas prices passed through to customers without a mark-up at Union Gas. This revenue increase is offset in expenses.

•

A $102 million increase due to foreign exchange rates favorably impacting revenues from the Canadian operations as a result of the strengthening Canadian dollar (partially offset by currency impacts to expenses), and

•

A $16 million increase from completed and operational pipeline expansion projects in the United States, partially offset by

•

A $104 million decrease in gas distribution revenues at Union Gas primarily resulting from lower gas usage due to unseasonably warmer weather.

Operating Expenses. The increase was driven primarily by:

•

A $222 million increase due to new Canadian assets, primarily gas purchase cost associated with the Empress System

•

A $145 million increase related to increased natural gas prices at Union Gas. This amount is offset in revenues

•

An $81 million increase caused by foreign exchange impacts (offset by currency impacts to revenues, as discussed above) and

•

A $43 million increase in U.S. O&M primarily related to higher insurance premiums, pipeline integrity costs, and other increased transmission and storage operation expenses, partially offset by

•

An $82 million decrease in gas purchase costs, primarily resulting from lower gas usage due to unseasonably warmer weather and

•

A $15 million decrease related to the resolution of prior tax years’ ad valorem tax.

Gain on sale of other assets and other, net. The increase was driven primarily by a $23 million gain on the settlement of a customer’s transportation contract and a $5 million gain on the sale of Stone Mountain assets.

Other Income and expenses, net. The decrease was driven primarily by a $5 million construction fee received from an affiliate as a result of the successful completion of the Gulfstream Natural Gas System LLC (Gulfstream), 50% owned by Duke Energy, Phase II project in 2005.

EBIT . The increase in EBIT is due primarily to the increase in processing earnings (Empress System), the gain on settlement of a customer’s transportation contract, U.S. business expansion and operations and the strengthening Canadian currency, partially offset by the 2005 Gulfstream success fee and Union weather and operations.

PART I

Matters Impacting Future Results

In June 2006, the Board of Directors of Duke Energy authorized management to pursue a plan to create two separate publicly traded companies by spinning off Duke Energy’s natural gas business to Duke Energy shareholders. The new natural gas company, which has yet to be named, would principally consist of Duke Energy’s Natural Gas Transmission business segment, which would include Union Gas, and would also include Duke Energy’s 50-percent ownership interest in DEFS. Approximately $3 billion of debt currently at Duke Capital is anticipated to transfer to the new natural gas company at the time of the spin-off. If completed, the decision to spin off the natural gas business is expected to deliver long-term value to shareholders and Duke Energy is targeting a January 1, 2007 effective date for the transaction. The results of the natural gas business are expected to be treated as discontinued operations in the period the spin-off is consummated.

Field Services


	Three Months Ended June 30,								Six Months Ended June 30,
	2006			2005		Increase (Decrease)			2006			2005		Increase (Decrease)
	(in millions, except where noted)
Operating revenues	$	—		$	2,872	$	(2,872	)	$	—		$	5,530	$	(5,530	)
Operating expenses		1			2,637		(2,636	)		3			5,210		(5,207	)
Gains on sales of other assets and other, net		—			—		—			—			2		(2	)

Operating (loss) income		(1	)		235		(236	)		(3	)		322		(325	)
Equity in earnings of unconsolidated affiliates ^(a)		149			—		149			295			—		295
Other income and expenses, net		—			7		(7	)		—			1,258		(1,258	)
Minority interest expense		—			78		(78	)		—			497		(497	)

EBIT ^(a)	$	148		$	164	$	(16	)	$	292		$	1,083	$	(791	)

Natural gas gathered and processed/transported, TBtu/d ^(b)		6.7			6.9		(0.2	)		6.8			6.8		—
NGL production, MBbl/d ^(c)		365			365		—			361			362		(1	)
Average natural gas price per MMBtu ^(d)(e)	$	6.79		$	6.73	$	0.06		$	7.88		$	6.50	$	1.38
Average NGL price per gallon ^(e)	$	0.98		$	0.75	$	0.23		$	0.93		$	0.74	$	0.19

(a)	Includes Duke Energy’s 50% equity in earnings of DEFS net income subsequent to the deconsolidation of DEFS effective July 1, 2005. Results of DEFS for the three and six months ended June 30, 2005 are presented on a consolidated basis.

(b)	Trillion British thermal units per day

(c)	Thousand barrels per day

(d)	Million British thermal units. Average price based on NYMEX Henry Hub

(e)	Does not reflect results of commodity hedges.

Three months ended June 30, 2006 as Compared to June 30, 2005

Operating Revenues. The decrease was due to the DEFS disposition transaction and subsequent deconsolidation of DEFS.

Operating Expenses. The decrease was due to the DEFS disposition transaction and subsequent deconsolidation of DEFS.

Equity in Earnings of Unconsolidated Affiliates. The increase is due to Duke Energy’s 50% of equity in earnings of DEFS’ net income for the three months ended June 30, 2006. DEFS’ earnings during the three months ended June 30, 2006 have continued to be favorably impacted by increased commodity prices as compared to the prior period.

Other Income and expenses, net . The decrease is due to the DEFS disposition transaction and subsequent deconsolidation of DEFS.

Minority Interest Expense. The decrease was due to the DEFS disposition transaction and subsequent deconsolidation of DEFS.

EBIT . The decrease in EBIT resulted from the DEFS disposition transaction, which reduced Duke Energy’s ownership interest in DEFS from 69.7% to 50%. These decreases were partially offset by increased commodity prices for the three months ended June 30, 2006 as compared to the prior period.

PART I

Six months ended June 30, 2006 as Compared to June 30, 2005

Operating Revenues. The decrease was due to the DEFS disposition transaction and subsequent deconsolidation of DEFS.

Operating Expenses. The decrease was due to the DEFS disposition transaction and subsequent deconsolidation of DEFS. Operating expenses for the six months ended June 30, 2005 were impacted by approximately $120 million of losses recognized due to the reclassification of pre-tax unrealized losses in AOCI as a result of the discontinuance of certain cash flow hedges entered into to hedge Field Services’ commodity price risk, which were previously accounted for as cash flow hedges.

Equity in Earnings of Unconsolidated Affiliates. The increase is due to Duke Energy’s 50% of equity in earnings of DEFS’ net income for the six months ended June 30, 2006. DEFS’ earnings during the six months ended June 30, 2006 have continued to be favorably impacted by increased commodity prices as compared to the prior period as well as a gain on sale of assets to an unrelated third party (of which Duke Energy’s 50% share was approximately $14 million). These increases have been partially offset by higher operating costs and pipeline integrity work for the six months ended June 30, 2006.

Other Income and expenses, net . The decrease is due to the DEFS disposition transaction and subsequent deconsolidation of DEFS. During the six months ended June 30, 2005, DEFS had a pre-tax gain on the sale of its wholly-owned subsidiary, TEPPCO GP, the general partner of TEPPCO LP of $1.1 billion, and Duke Energy had a pre-tax gain on the sale of its limited partner interest in TEPPCO LP of approximately $97 million. TEPPCO GP and Duke Energy’s limited partner interest in TEPPCO LP were each sold to Enterprise GP Holdings LP, an unrelated third party.

Minority Interest Expense. The decrease was due to the DEFS disposition transaction and subsequent deconsolidation of DEFS. Minority interest expense for the six months ended June 30, 2005 was due primarily to the gain on the sale of TEPPCO GP to Enterprise GP Holdings LP for approximately $1.1 billion, as discussed above.

EBIT . The decrease in EBIT resulted primarily from the gain on sale of TEPPCO GP and Duke Energy’s limited partner interest in TEPPCO LP during the six months ended June 30, 2005 and the DEFS disposition transaction, which reduced Duke Energy’s ownership interest in DEFS from 69.7% to 50%. These decreases were partially offset by increased commodity prices for the six months ended June 30, 2006 as compared to the prior period.

Supplemental Data

Below is supplemental information for DEFS operating results for the three and six months ended June 30, 2006:


(in millions)	Three Months Ended June 30, 2006		Six Months Ended June 30, 2006
Operating revenues	$	3,002	$	6,311
Operating expenses		2,657		5,651

Operating income		345		660
Other income and expenses, net		2		10
Interest expense, net		29		60
Income tax expense		19		20

Net income	$	299	$	590

Matters Impacting Future Results

As previously mentioned, in June 2006, the Board of Directors of Duke Energy authorized management to pursue a plan to create two separate publicly traded companies by spinning off Duke Energy’s natural gas business to Duke Energy shareholders. The new natural gas company, which has yet to be named, would principally consist of Duke Energy’s Natural Gas Transmission business segment, which would include Union Gas, and would also include Duke Energy’s 50-percent ownership interest in DEFS. If completed, the decision to spin off the natural gas business is expected to deliver long-term value to shareholders and Duke Energy is targeting a January 1, 2007 effective date for the transaction.

In July 2006, the State of New Mexico Environment Department issued Compliance Order to DEFS that list air quality violations during the past five year at three DEFS owned or operated facilities in New Mexico. DEFS intends to contest these allegations. Management of DEFS is unable to express an opinion regarding the probable outcome of this matter at this time.

PART I

Commercial Power


	Three Months Ended June 30,									Six Months Ended June 30,
	2006			2005			Increase (Decrease)			2006			2005			Increase (Decrease)
	(in millions, except where noted)
Operating revenues	$	447		$	36		$	411		$	463		$	49		$	414
Operating expenses		436			52			384			476			83			393
Losses on sales of other assets and other, net		(5	)		—			(5	)		(5	)		—			(5	)

Operating income (loss)		6			(16	)		22			(18	)		(34	)		16
Other income and expenses, net		14			—			14			11			—			11

EBIT	$	20		$	(16	)	$	36		$	(7	)	$	(34	)	$	27

Actual Plant Production, Gwh		5,363			516			4,847			5,380			706			4,674

Three Months Ended June 30, 2006 as Compared to June 30, 2005

Operating Revenues. The increase was primarily driven by the acquisition of Cinergy assets for which results are reflected for the three months ended June 30, 2006, but are not included in the same period in 2005. Operating revenues associated with the DENA Midwest plants were approximately $7 million lower for the three months ended June 30, 2006 compared to the same period in the prior year primarily due to lower plant production.

Operating Expenses. The increase was primarily driven by the acquisition of Cinergy assets for which results are reflected for the three months ended June 30, 2006, but are not included in the same period in 2005. Operating expenses associated with the DENA Midwest plants were approximately $5 million lower for the three months ended June 30, 2006 compared to the same period in the prior year primarily due to lower plant production.

EBIT. The increase was due primarily to the acquisition of Cinergy assets for which results are reflected for the three months ended 2006, but are not included in 2005. Results for the three months ended June 30, 2005 relate to the DENA Midwest assets. EBIT for these assets increased approximately $1 million for the three months ended June 30, 2006 as compared to the same period in the previous year.

Six Months Ended June 30, 2006 as Compared to June 30, 2005

Operating Revenues. The increase was primarily driven by the acquisition of Cinergy assets for which results are reflected from the date of acquisition and thereafter, but are not included in the same period in 2005. Operating Revenues associated with the DENA Midwest plants were approximately $4 million lower for the six months ended June 30, 2006 compared to the same period in the prior year primarily due to lower plant production

Operating Expenses. The increase was primarily driven by the acquisition of Cinergy assets for which results are reflected from the date of acquisition and thereafter, but are not included in the same period in 2005. Operating Expenses associated with the DENA Midwest plants were approximately $4 million lower for the six months ended June 30, 2006 compared to the same period in the prior year primarily due to lower plant production.

EBIT. The increase was due primarily to the acquisition of Cinergy assets for which results are reflected from the date of acquisition and thereafter, but are not included in the same period in 2005. Results for the six months ended 2005 relate to the DENA Midwest assets. EBIT for these assets decreased approximately $6 million in 2006 compared to the same period in the prior year.

PART I

International Energy


	Three Months Ended June 30,							Six Months Ended June 30,
	2006		2005		Increase (Decrease)			2006		2005		Increase (Decrease)
	(in millions, except where noted)
Operating revenues	$	250	$	182	$	68		$	481	$	350	$	131
Operating expenses		233		127		106			390		246		144

Operating income		17		55		(38	)		91		104		(13	)
Other income and expenses, net		11		34		(23	)		31		55		(24	)
Minority interest expense		2		3		(1	)		9		5		(4	)

EBIT	$	26	$	86	$	(60	)	$	113	$	154	$	(41	)

Sales, GWh		5,232		4,527		705			10,230		9,062		1,168
Proportional megawatt capacity in operation									3,993		4,139		(146	)

Three Months Ended June 30, 2006 as Compared to June 30, 2005

Operating Revenues. The increase was primarily driven by:

•

A $28 million increase in Peru due to increased ownership and resulting consolidation of Aguaytia.

•

A $17 million increase in El Salvador due to higher energy prices and a favorable change in regulatory price bid methodology.

•

A $11 million increase in Brazil mainly due to favorable exchange rates and higher average prices, and

•

An $8 million increase in Argentina primarily due to higher generation and prices and increased gas marketing sales.

Operating Expenses. The increase was primarily driven by:

•

A $38 million increase in Mexico due to a reserve on notes receivable from the Campeche equity investment.

•

A $31 million increase in Peru due to increased ownership and resulting consolidation of Aguaytia.

•

A $17 million increase in El Salvador primarily due to higher fuel prices and increased fuel volumes as a result of increased generation, and

•

A $14 million increase in Brazil mainly due to unfavorable exchange rates, increased transmission fees and lower costs in 2005 due to tax credit adjustment.

Other income and expenses, net. The decrease was driven primarily by a $17 million impairment of the Campeche equity investment and a $6 million decrease in Aguaytia as a result of consolidation.

EBIT. The decrease in EBIT was primarily due to an impairment of the Campeche equity investment and note receivable reserve, higher purchased power costs due to an unplanned outage in Aguaytia and unfavorable hydrology in Peru and Brazil.

Six Months Ended June 30, 2006 as Compared to June 30, 2005

Operating Revenues. The increase was primarily driven by:

•

A $48 million increase in Peru due to increased ownership and resulting consolidation of Aguaytia.

•

A $37 million increase in El Salvador mainly due to higher energy prices as a result of a favorable change in regulatory price bid methodology.

•

A $25 million increase in Brazil due to favorable exchange rates, higher average energy prices, offset by lower volumes, and

•

A $17 million increase in Argentina mainly due to higher energy prices and increased generation due to favorable hydrology.

Operating Expenses. The increase was primarily driven by:

•

A $44 million increase in Peru due to increased ownership and resulting consolidation of Aguaytia.

•

A $38 million increase in Mexico mainly due to a reserve on notes receivable from the Campeche equity investment.

•

A $35 million increase in El Salvador primarily due to higher fuel prices and increased fuel volumes as a result of increased generation, and

•

A $20 million increase in Brazil mainly due to unfavorable exchange rates, increased transmission fees and lower costs in 2005 due to tax credit adjustment.

PART I

Other income and expenses, net. The decrease was primarily driven by a $17 million impairment of the Campeche equity investment and an $8 million decrease in Aguaytia as a result of consolidation.

EBIT. The decrease in EBIT was primarily due to an impairment in Mexico, higher power purchases in Peru and decreased generation in Brazil, offset by favorable exchange rates primarily in Brazil and favorable hydrology and energy prices in Argentina.

Matters Impacting Future Results

The Bolivian government has announced plans to nationalize its energy infrastructure. As a result, Management is currently monitoring the potential impact on its 50 percent interest in Corani. Depending upon future actions of the Bolivian government, Duke Energy’s investment in Corani could become impaired.

Crescent


	Three Months Ended June 30,								Six Months Ended June 30,
	2006		2005			Increase (Decrease)			2006		2005			Increase (Decrease)
	(in millions)
Operating revenues	$	85	$	112		$	(27	)	$	156	$	176		$	(20	)
Operating expenses		60		79			(19	)		121		130			(9	)
Gains on sales of investments in commercial and multi-family real estate		145		12			133			171		54			117

Operating income		170		45			125			206		100			106
Other income and expenses, net		5		(2	)		7			13		(2	)		15
Minority interest expense		1		5			(4	)		3		8			(5	)

EBIT	$	174	$	38		$	136		$	216	$	90		$	126

Three Months Ended June 30, 2006 as Compared to June 30, 2005

Operating Revenues. The decrease was driven primarily by a $28 million decrease in residential developed lot sales, due to decreased sales at the LandMar division in Florida, Palmetto Bluff in South Carolina and The Rim in Payson, Arizona.

Operating Expenses. The decrease was driven primarily by a $22 million decrease in the cost of residential developed lot sales as noted above.

Gains on Sales of Investments in Commercial and Multi-Family Real Estate . The increase was driven primarily by an $81 million gain on the sale of two office buildings at Potomac Yard in Washington, DC along with a $52 million land sale at Lake Keowee in northwestern South Carolina as compared to minimal sales in the second quarter of 2005.

Other Income and expenses, net . The increase is primarily due to an increase of approximately $4 million in equity earnings from joint ventures and an approximate $3 million gain from the sale of an interest in a portfolio of commercial office buildings.

EBIT. The increase was primarily due to the sale of the Potomac Yard office buildings and the Lake Keowee land sale as noted above.

Six Months Ended June 30, 2006 as Compared to June 30, 2005

Operating Revenues. The decrease was driven primarily by a $19 million decrease in residential developed lot sales, due to decreased sales at the LandMar division in Florida and The Rim in Payson, Arizona offset by increased sales at Palmetto Bluff in South Carolina and Springfield in Charlotte, NC.

Operating Expenses. The decrease was driven primarily by a $17 million decrease in the cost of residential developed lot sales, due to decreased developed lot sales at the projects noted above. This was partially offset by a $7 million increase in administrative expenses due to incentive accruals in the first half of 2006 tied to operating results.

Other Income and expenses, net . The increase is primarily due to an increase of approximately $10 million of equity earnings from joint ventures along with an approximate $5 million gain from the sale of an interest in a portfolio of commercial office buildings.

PART I

EBIT. The increase was primarily due to the sale of the Potomac Yard office buildings and the Lake Keowee land sale as noted above.

Matters Impacting Future Results

During the second quarter of 2006, the Board of Directors of Duke Energy authorized Duke Energy management to explore the creation of a joint venture with an undisclosed potential partner. If a joint venture is formed, it is expected that the joint venture would be levered.

Other


	Three Months Ended June 30,									Six Months Ended June 30,
	2006			2005			Increase (Decrease)			2006			2005			Increase (Decrease)
	(in millions)
Operating revenues	$	125		$	145		$	(20	)	$	271		$	179		$	92
Operating expenses		267			252			15			468			477			(9	)
(Losses) gains on sales of other assets and other, net		(8	)		—			(8	)		(3	)		3			(6	)

Operating loss		(150	)		(107	)		(43	)		(200	)		(295	)		95
Other income and expenses, net		(27	)		2			(29	)		(39	)		5			(44	)
Minority interest benefit		(3	)		(3	)		—			(7	)		(4	)		(3	)

EBIT	$	(174	)	$	(102	)	$	(72	)	$	(232	)	$	(286	)	$	54

Three Months Ended June 30, 2006 as Compared to June 30, 2005

Operating Revenues . The decrease was driven primarily by the continued wind-downs of Duke Energy’s 50% interest in Duke/Fluor Daniel (D/FD), Duke Energy Trading and Marketing (DETM) and Duke Energy Merchants, LLC (DEM), partially offset by an approximate $20 million increase as a result of the prior year impact of realized and unrealized mark-to-market losses on certain discontinued cash flow hedges originally entered into to hedge Field Services’ commodity price risk which were accounted for as Operating Revenues prior to the deconsolidation of DEFS, effective July 1, 2005.

Operating Expenses . The increase was driven primarily by $74 million of charges in 2006 associated with costs to achieve the Cinergy merger, partially offset by decreases related to the continued wind-downs of D/FD, DETM and DEM, and a $20 million reduction in charges for liabilities associated with mutual insurance companies

Other Income and Expenses, net . The decrease was driven primarily by a $21 million net loss resulting from realized and unrealized mark-to-market impacts in 2006 of certain discontinued cash flow hedges originally entered into to hedge Field Services’ commodity price risk which are recorded in Other income and expenses, net on the Consolidated Statements of Operations subsequent to the deconsolidation of DEFS, effective July 1, 2005.

EBIT. The decrease was due primarily to the charges in 2006 associated with costs to achieve the Cinergy merger, partially offset by the reduction in charges for liabilities associated with mutual insurance companies.

Six Months Ended June 30, 2006 as Compared to June 30, 2005

Operating Revenues . The increase was driven primarily by an approximate $130 million increase as a result of the prior year impact of realized and unrealized mark-to-market losses on certain discontinued cash flow hedges originally entered into to hedge Field Services’ commodity price risk which were accounted for as Operating Revenues prior to the deconsolidation of DEFS, effective July 1, 2005. This increase was partially offset by decreases associated with the continued wind-downs of D/FD, DETM and DEM.

Operating Expenses . The decrease was driven primarily by a $42 million reduction in charges for liabilities associated with mutual insurance companies, including a prior year $28 million mutual insurance liability adjustment, which was a correction of an immaterial accounting error. Also contributing to the decrease were reductions associated with the continued wind-downs of D/FD, DETM and DEM. These decreases were partially offset by charges in 2006 of $78 million associated with costs to achieve the Cinergy merger.

Other Income and Expenses, net . The decrease was driven primarily by a $45 million net loss resulting from realized and unrealized mark-to-market impacts in 2006 of certain discontinued cash flow hedges originally entered into to hedge Field Services’ commodity price risk which are recorded in Other income and expenses, net on the Consolidated Statements of Operations subsequent to the deconsolidation of DEFS, effective July 1, 2005.

PART I

EBIT. The increase was due primarily to the realized and unrealized mark-to-market impact of certain discontinued cash flow hedges originally entered into to hedge Field Services’ commodity price risk, and lower charges for liabilities associated with mutual insurance companies. These increases were partially offset by the charges in 2006 associated with costs to achieve the Cinergy merger.

LIQUIDITY AND CAPITAL RESOURCES

Operating Cash Flows

Net cash provided by operating activities decreased $584 million for the six months ended June 30, 2006 compared to the same period in 2005. This change was driven primarily by:

•

An approximate $400 million decrease in 2006 due to the net settlement of remaining DENA contracts

•

The impacts of the deconsolidation of DEFS, LLC, effective July 1, 2005

•

The settlement of the payable to Barclays (approximately $600 million) in 2006, partially offset by

•

Collateral received by Duke Energy (approximately $540 million) in 2006 from Barclays

Investing Cash Flows

Net cash provided by investing activities increased $105 million for the six months ended June 30, 2006 compared to the same period in 2005. This change was driven primarily by:

•

Approximately $1.6 billion in proceeds received from the sale of DENA in 2006, offset by approximately $1.2 billion in proceeds received in 2005 from the sale of TEPPCO GP and Duke Energy’s interest in TEPPCO LP

•

An approximate $147 million increase in 2006 due to cash acquired as a result of the merger with Cinergy, partially offset by

•

An approximate $459 million increase in 2006 capital and investment expenditures, primarily related to Cinergy and additional investments at Crescent

Financing Cash Flows and Liquidity

Net cash used in financing activities decreased $245 million for the six months ended June 30, 2006, compared to the same period in 2005. This change was driven primarily by:

•

An approximate $400 million decrease in share repurchases under the accelerated share repurchase plan due to the repurchase of 32.6 million shares of common stock for approximately $900 million during the six months ended June 30, 2005, compared to the repurchase of 17.5 million shares for approximately $500 million during the six months ended June 30, 2006, partially offset by

•

An approximate $40 million increase in the redemptions of long-term debt in 2006, net of issuances

•

An approximate $160 million increase in dividends paid due to the increase in the quarterly dividend paid per share.

Duke Energy previously announced plans to execute up to approximately $2.5 billion in common stock repurchases over a three year period. On May 9, 2005, in connection with the announcement of the merger with Cinergy, Duke Energy suspended additional repurchases, pending further assessment. At the time of suspension, Duke Energy had repurchased approximately $909 million of common stock. In the first quarter of 2006, as a result of the March 10 ^, 2006 shareholder approval of the merger, Duke Energy’s Board of Directors authorized the repurchase of up to an additional $1 billion of common stock under the previously announced share repurchase plan. During the three and six months ended June 30, 2006, Duke Energy repurchased approximately 15.1 million and 17.5 million shares, respectively, for total consideration of approximately $430 million and $500 million, respectively. The repurchases and corresponding commissions and other fees were recorded in Common Stockholder’s Equity as a reduction in common stock and additional paid-in capital. Through June 30, 2006, Duke Energy has repurchased approximately 50 million shares of common stock for approximately $1.4 billion. In June 2006, Duke Energy suspended additional repurchases of Duke Energy common stock under the repurchase plan due to its plan to spin off the natural gas businesses.

Significant Financing Activities. During the six months ended June 30, 2006, Duke Energy’s consolidated credit capacity increased by approximately $764 million, primarily due to the merger with Cinergy. This increase was net of other reductions in credit capacity due to the terminations of an $800 million syndicated credit facility and $460 million of other bi-lateral credit facilities. The terminations of these credit facilities primarily reflect Duke Energy’s reduced liquidity needs as a result of exiting the DENA business.

PART I

During 2006, Duke Energy has repurchased approximately 17.5 million shares of its common stock for approximately $500 million. In connection with the plan to spin off Duke Energy’s natural gas business to Duke Energy shareholders (see “Other Issues”), the share repurchase program has since been suspended.

In April 2006, Duke Energy’s $742 million of convertible debt became convertible into approximately 31.7 million shares of Duke Energy common stock due to the market price of Duke Energy common stock. Holders of the convertible debt were able to exercise their right to convert on or prior to June 30, 2006. During the conversion period, approximately $611 million of debt was converted into approximately 26 million shares of Duke Energy Common Stock. At June 30, 2006, the balance of the convertible debt is approximately $131 million and remains convertible in the third quarter of 2006 into approximately 5.6 million shares of Duke Energy common stock.

In December 2004, Duke Energy reached an agreement to sell its partially completed Grays Harbor power generation facility to an affiliate of Invenergy LLC. In 2004, Duke Energy terminated its capital lease with the dedicated pipeline which would have transported natural gas to Grays Harbor. As a result of this termination, approximately $94 million was paid by Duke Energy in January 2005.

On March 1, 2005, redemption notices were sent to the bondholders of the $100 million PanEnergy 8.625% bonds due in 2025. These bonds were redeemed on April 15, 2005 at a redemption price of 104.03 or approximately $104 million.

During the three-month period ended March 31, 2005, Duke Energy increased the portion of outstanding commercial paper balances classified as long-term debt from $150 million to $300 million. This non-current classification is due to the existence of long-term credit facilities which back-stop these commercial paper balances along with Duke Energy’s intent to refinance such balances on a long-term basis.

Effective with the third quarter 2006, the Board of Directors of Duke Energy have approved a quarterly dividend increase of $0.01 per share, increasing the annual dividend to $1.28 per share.

Available Credit Facilities and Restrictive Debt Covenants. Duke Energy’s debt and credit agreements contain various financial and other covenants. Failure to meet those covenants beyond applicable grace periods could result in accelerated due dates and/or termination of the agreements. As of June 30, 2006, Duke Energy was in compliance with those covenants. In addition, some credit agreements may allow for acceleration of payments or termination of the agreements due to nonpayment, or to the acceleration of other significant indebtedness of the borrower or some of its subsidiaries. None of the debt or credit agreements contain material adverse change clauses.

Credit Ratings. Duke Energy and certain subsidiaries each hold credit ratings by Standard & Poor’s (S&P), Moody’s Investors Service (Moody’s) and Dominion Bond Rating Service (DBRS).

The most recent rating action by S&P occurred in June 2006 when S&P changed the outlook of Duke Capital Texas Eastern Transmission, LP, Union Gas and Westcoast Energy Inc. from positive to developing following Duke Energy’s announcement of the separation of the electric and gas businesses. S&P noted the developing outlook reflects a measure of uncertainty as to how the new gas company will be capitalized and funded. In May 2006, S&P changed the outlook of Duke Energy and all of its subsidiaries (with the exception of Maritimes & Northeast Pipeline, LLC and Maritimes & Northeast Pipeline, LP (collectively M&N Pipeline) and Duke Energy Trading and Marketing, LLC from stable to positive reflecting Duke Energy’s announcement to sell Cinergy’s commercial trading and marketing operations. In April 2006, following the completion of Duke Energy’s merger with Cinergy, S&P lowered the credit rating of Cinergy Corp. and raised the credit rating of Duke Capital each one ratings level as disclosed in the table below. At the same time, S&P removed Cinergy and its subsidiaries from credit-watch negative, assigned a credit rating to Duke Power Company LLC and left the remaining credit ratings in the table disclosed below unchanged. At the completion of S&P’s April actions, all the credit ratings were on stable outlook. S&P’s ratings action in April also included a lowering of Cinergy’s Corporate Credit Rating (CCR) consistent with Duke Energy’s CCR as disclosed in the table below. S&P last affirmed its rating for M&N Pipeline in July 2006 where it has remained unchanged with a stable outlook for the last several years.

The most recent rating action by Moody’s for Duke Energy and its subsidiaries (with the exception of M&N Pipeline) occurred in April 2006 following Duke Energy’s completion of the merger with Cinergy. Moody’s upgraded the credit ratings of Duke Power Company LLC (formerly rated as Duke Energy by Moody’s), Duke Capital and Texas Eastern Transmission, LP one ratings level each and assigned an issuer rating to New Duke Energy as disclosed in the table below. Moody’s concluded their ratings action placing New Duke Energy and Duke Power Company LLC on positive outlook and Duke Capital and Texas Eastern Transmission, LP on stable outlook. Moody’s also confirmed all of Cinergy and its subsidiaries credit ratings and changed the outlook to positive with the exception of PSI Energy, Inc. Moody’s noted in their actions the substantial reduction in business and operating risk of Duke Power Company LLC from the distribution of its ownership in Duke Capital to a new holding company and the substantial reduction in business and operating risk of Duke Capital through the restructuring of its ownership in DEFS and the divestiture of the Duke Energy North America merchant generation assets and

PART I

trading book. Moody’s also noted the upgrade at Texas Eastern, LP as connected to its parent Duke Capital. In August 2005, Moody’s concluded a review of M&N Pipeline and downgraded the credit ratings one ratings level to the respective ratings disclosed in the table below concluding their actions with a stable outlook. Moody’s actions were primarily as a result of their concerns over the downward revisions in the reserve estimates for the Sable Offshore Energy Project (SOEI) and reduced production by SOEI producers. In August 2006, Moody’s revised the outlook for Maritimes & Northeast Pipelines, LLC to negative, noting the potential for a somewhat weaker shipper profile resulting from a recently announced expansion project on the U.S. portion of the pipeline.

The most recent rating action by DBRS occurred in June 2006 when DBRS confirmed the stable trend of the entities disclosed in the table below following Duke Energy’s announcement of the separation of the electric and gas businesses. Each of the credit ratings assigned by DBRS to the entities below has remained unchanged for the last several years with a stable trend.

The following table summarizes the August 1, 2006 credit ratings from the agencies retained by Duke Energy to rate its securities, its principal funding subsidiaries and its trading and marketing subsidiary DETM.

Credit Ratings Summary as of August 1, 2006


	Standard and Poor’s	Moody’s Investor Service	Dominion Bond Rating Service
Duke Energy ^(a)	BBB	Baa2	Not applicable
Duke Power Company LLC ^(b)	BBB	A3	Not applicable
Duke Capital LLC ^(b)	BBB	Baa2	Not applicable
Cinergy ^(b)	BBB-	Baa2	Not applicable
The Cincinnati Gas & Electric Company ^(b)	BBB	Baa1	Not applicable
PSI Energy, Inc. ^(b)	BBB	Baa1	Not applicable
The Union Light, Heat and Power Company ^(b)	BBB	Baa1	Not applicable
Texas Eastern Transmission, LP ^(b)	BBB	Baa1	Not applicable
Westcoast Energy Inc. ^(b)	BBB	Not applicable	A(low)
Union Gas ^(b)	BBB	Not applicable	A
Maritimes & Northeast Pipeline, LLC ^(c)	A	A2	A
Maritimes & Northeast Pipeline, LP ^(c)	A	A2	A
Duke Energy Trading and Marketing, LLC ^(d)	BBB-	Not applicable	Not applicable

(a)	Represents corporate credit rating and issuer rating for S&P and Moody’s respectively

(b)	Represents senior unsecured credit rating

(c)	Represents senior secured credit rating

(d)	Represents corporate credit rating

These entities credit ratings are dependent upon, among other factors, the ability to generate sufficient cash to fund capital and investment expenditures, while maintaining the strength of their current balance sheets. In addition, the M&N Pipeline ratings are dependent upon, among other factors, the future gas supply availability and potential changes in customer credit profiles. These credit ratings could be negatively impacted if as a result of market conditions or other factors, these entities are unable to maintain their current balance sheet strength, or if earnings and cash flow outlook materially deteriorates, or if the gas supply availability contracted on the M&N pipeline materially deteriorates, or the M&N customer credit profiles materially deteriorates.

Prior to June 30, 2006, business activity by DENA generated the majority of Duke Energy’s collateral requirements. During the third quarter of 2005, the Board of Directors of Duke Energy authorized and directed management to execute the sale or disposition of substantially all of DENA’s remaining assets and contracts outside the Midwestern United States. On November 18, 2005, Duke Energy announced it signed an agreement to transfer substantially all of the DENA portfolio of derivatives contracts to Barclays. Under the agreement, Barclays acquired substantially all of DENA’s outstanding gas and power derivatives contracts which essentially eliminated Duke Energy’s credit, collateral, market and legal risk associated with DENA’s derivative trading positions effective on the date of signing. Substantially all of the underlying contracts have been transferred to Barclays.

Duke Energy operates a commercial marketing and trading business that was acquired as part of the merger with Cinergy in April 2006. In June 2006, Duke Energy announced it had reached an agreement to sell Cinergy Marketing and Trading, LP, and Cinergy Canada, Inc., as well as associated contracts. The sale is subject to Federal Energy Regulatory Commission and Federal Reserve Board approvals, as well as Canadian regulatory approvals, and is anticipated to close in the third quarter of 2006. Once closed, the buyer will assume the credit, collateral, market and legal risk associated with the trading positions acquired.

PART I

A reduction in the credit rating of Cinergy Corp to below investment grade as of June 30, 2006 would have required the posting of additional collateral of up to approximately $260 million, of which $82 million is related to CG&E, a wholly-owned subsidiary of Cinergy Corp.

A reduction in the credit rating of Duke Capital to below investment grade as of June 30, 2006 would have resulted in Duke Capital posting additional collateral of up to approximately $320 million. The majority of this collateral is related to outstanding surety bonds.

Duke Energy would fund any additional collateral requirements through a combination of cash on hand and the use of credit facilities. Additionally, if credit ratings for Duke Energy or its affiliates fall below investment grade there is likely to be a negative impact on its working capital and terms of trade that is not possible to fully quantify, in addition to the posting of additional collateral and segregation of cash described above.

Other Financing Matters. As of June 30, 2006, Duke Energy and its subsidiaries had effective SEC shelf registrations for up to $2,790 million in gross proceeds from debt and other securities, which include approximately $1,248 million of effective registrations at legacy Cinergy. Additionally, as of June 30, 2006, Duke Energy had 700 million Canadian dollars (approximately U.S. $618 million) available under Canadian shelf registrations for issuances in the Canadian market. Of the 700 million Canadian dollars available under Canadian shelf registrations, 200 million expired in July 2006 and 500 million expires in May 2008. In July 2006, an additional 600 million Canadian dollars (approximately U.S. $529) was added to the amount available under Canadian shelf registrations that expires in August 2008.

Off-Balance Sheet Arrangements

During the six months ended June 30, 2006, there were changes to Duke Energy’s off-balance sheet arrangements, primarily related to the merger with Cinergy. Cinergy has an agreement to sell certain of their accounts receivable and related collections to Cinergy Receivables, which is a qualified special purpose entity (QSPE) pursuant to SFAS No. 140, “ Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities, ” and therefore is an unconsolidated entity of Duke Energy. For further information on Cinergy’s off-balance sheet arrangements, see “Off-Balance Sheet Arrangements” in Cinergy’s Annual Report on Form 10-K for the year-ended December 31, 2005. For information on Duke Energy’s off-balance sheet arrangements, see “Off-Balance Sheet Arrangements” in Duke Energy’s Annual Report on Form 10-K for the year-ended December 31, 2005.

Contractual Obligations

Duke Energy enters into contracts that require cash payment at specified periods, based on specified minimum quantities and prices. During the six months ended June 30, 2006, there were material changes in Duke Energy’s contractual obligations from the amounts reported in Duke Energy’s Annual Report on Form 10-K for the year-ended December 31, 2005. These changes primarily relate to approximately $6.7 billion of contractual obligations assumed as part of the merger with Cinergy, which are primarily comprised of payments on long-term debt, payments under operating and capital leases and contracts to purchase fuel, primarily coal. For an in-depth discussion of Duke Energy’s contractual obligations, see “Contractual Obligations” and “Quantitative and Qualitative Disclosures about Market Risk” in “Management’s Discussion and Analysis of Results of Operations and Financial Condition” in Duke Energy’s Annual Report on Form 10-K for the year ended December 31, 2005. Additionally, for information related to Cinergy, see “Contractual Cash Obligations” in “Management’s Discussion and Analysis—Liquidity and Capital Resources” in Cinergy’s Annual Report of Form 10-K for the year ended December 31, 2005.

OTHER ISSUES

Plan to Separate Duke Energy’s Natural Gas and Electric Power Businesses. In June 2006, the Board of Directors of Duke Energy authorized management to pursue a plan to create two separate publicly traded companies by spinning off Duke Energy’s natural gas business to Duke Energy shareholders. The new gas company, which has yet to be named, will consist of Duke Energy’s Natural Gas Transmission business segment, which includes Union Gas, and Duke Energy’s 50-percent ownership interest in Duke Energy Field Services (DEFS). The businesses remaining in Duke Energy will be the U.S. Franchised Electric and Gas business segment, the Commercial Power business segment, the International business segment and Crescent Resources. Approximately $3 billion of debt currently at Duke Capital is anticipated to transfer to the new natural gas company at the time of the spin-off. Duke Energy is targeting a January 1, 2007 effective date for the transaction and expects the transaction to qualify for tax-free treatment for U.S. federal income tax purposes to both Duke Energy and its shareholders. The transaction would require Virginia State Corporation Commission approval and Duke Energy applied for such approval on August 1, 2006. In addition, approval from the Federal Communications Commission would be required for the indirect change in control over various licenses from Duke Energy to the new gas company. Duke Energy expects to make the requisite applications in the third quarter 2006.

(For additional information on other issues related to Duke Energy, see Note 16 to the Consolidated Financial Statements, “Regulatory Matters.”)

PART I

New Accounting Standards

The following new accounting standards have been issued, but have not yet been adopted by Duke Energy as of June 30, 2006:

Statement of Financial Accounting Standards (SFAS) No. 155, “Accounting for Certain Hybrid Financial Instruments—an amendment of FASB Statements No. 133 and 140” (SFAS No. 155). In February 2006, the Financial Accounting Standards Board (FASB) issued SFAS No. 155, which amends SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” and SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities.” SFAS No. 155 allows financial instruments that have embedded derivatives to be accounted for at fair value at acquisition, at issuance, or when a previously recognized financial instrument is subject to a remeasurement (new basis) event, on an instrument-by-instrument basis, in cases in which a derivative would otherwise have to be bifurcated. This Statement is effective for Duke Energy for all financial instruments acquired, issued, or subject to remeasurement after January 1, 2007, and for certain hybrid financial instruments that have been bifurcated prior to the effective date, for which the effect is to be reported as a cumulative-effect adjustment to beginning retained earnings. Duke Energy does not anticipate the adoption of SFAS No. 155 will have any material impact on its consolidated results of operations, cash flows or financial position.

SFAS No. 156, “Accounting for Servicing of Financial Assets—an amendment of FASB Statement No. 140” (SFAS No. 156). In March 2006, the FASB issued SFAS No. 156, which amends SFAS No . 140 , “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities.” SFAS No 156 requires recognition of a servicing asset or liability when an entity enters into arrangements to service financial instruments in certain situations. Such servicing assets or servicing liabilities are required to be initially measured at fair value, if practicable. SFAS No. 156 also allows an entity to subsequently measure its servicing assets or servicing liabilities using either an amortization method or a fair value method. This Statement is effective for Duke Energy as of January 1, 2007, and must be applied prospectively, except that where an entity elects to remeasure separately recognized existing arrangements and reclassify certain available-for-sale securities to trading securities, any effects must be reported as a cumulative-effect adjustment to retained earnings. Duke Energy does not anticipate the adoption of SFAS No. 156 will have any material impact on its consolidated results of operations, cash flows or financial position.

FASB Staff Position (FSP) No. FIN 46 (R)-6, “Determining the Variability to Be Considered In Applying Interpretation No. 46(R) (FSP-FIN 46(R)-6).” In April 2006, the FASB staff issued FSP No. FIN 46 (R)-6 to address how to determine the variability to be considered in applying FASB Interpretation No. 46(R), Consolidation of Variable Interest Entities. The variability that is considered in applying Interpretation 46(R) affects the determination of whether the entity is a variable interest entity (VIE), which interests are variable interests in the entity, and which party, if any, is the primary beneficiary of the VIE. The variability affects the calculation of expected losses and expected residual returns. This guidance will be applied prospectively to all entities with which Duke Energy first becomes involved or existing entities for which a reconsideration event occurs after July 1, 2006. Duke Energy does not anticipate the adoption of FSP No. FIN 46 (R)-6 will have any material impact on its consolidated results of operations, cash flows or financial position.

EITF Issue No. 05-1, “Accounting for the Conversion of an Instrument that Becomes Convertible Upon the Issuer’s Exercise of a Call Option” (EITF 05-1). In June 2006, the EITF reached a consensus on Issue No. 05-1. The consensus requires that the issuance of equity securities to settle a debt instrument (pursuant to the instrument’s original conversion terms) that became convertible upon the issuer’s exercise of a call option be accounted for as a conversion if the debt instrument contained a substantive conversion feature as of its issuance date. If the debt instrument did not contain a substantive conversion option as of its issuance date, the issuance of equity securities to settle the debt instrument should be accounted for as a debt extinguishment. The consensus is effective for Duke Energy for all conversions within its scope that result from the exercise of call options beginning July 1, 2006. Duke Energy does not anticipate the adoption of EITF Issue 05-1 will have any material impact on its consolidated results of operations, cash flows or financial position.

PART I

may include, but are not limited to, sales, use, value added, and some excise taxes. For taxes within the issue’s scope, the consensus requires that entities present such taxes on either a gross (i.e., include in revenues and costs) or net (i.e., exclude from revenues) basis according to their accounting policies, which should be disclosed. If such taxes are reported gross and are significant, entities should disclose the amounts of those taxes. Disclosures may be made on an aggregate basis. The consensus is effective for Duke Energy beginning January 1, 2007. Duke Energy does not anticipate the adoption of EITF Issue 06-3 will have any material impact on its consolidated results of operations.

Subsequent Events

For information on subsequent events related to acquisitions and dispositions, debt and credit facilities, discontinued operations and assets held for sale, regulatory matters, commitments and contingencies, and related party transactions, see Note 2, “Acquisitions and Dispositions,” Note 7, “Debt and Credit Facilities,” Note 13, “Discontinued Operations and Assets Held For Sale,” Note 16, “Regulatory Matters,” Note 17, “Commitments and Contingencies,” and Note 19, “Related Party Transactions,” to the Consolidated Financial Statements.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

For an in-depth discussion of Duke Energy’s market risks, see “Management’s Discussion and Analysis of Quantitative and Qualitative Disclosures about Market Risk” in Duke Energy’s Annual Report on Form 10-K for the year ended December 31, 2005.

Commodity Price Risk

Duke Energy is exposed to the impact of market fluctuations in the prices of natural gas, electricity, NGLs and other energy-related products marketed and purchased as a result of its ownership of energy related assets, remaining proprietary trading contracts, and interests in structured contracts classified as undesignated. Price risk represents the potential risk of loss from adverse changes in the market price of electricity or other energy commodities. Duke Energy employs established policies and procedures to manage its risks associated with these market fluctuations using various commodity derivatives, including forward contracts, futures, swaps and options.

Duke Energy’s largest commodity exposure is due to market price fluctuations of NGLs primarily in the Field Services segment and, to a lesser extent, in the Natural Gas Transmission segment. Based on a sensitivity analysis as of June 30, 2006, it was estimated that price changes of eighteen cents per gallon and fifteen cents per gallon in the price of NGLs (net of related hedges and an equivalent price change in crude oil) would have a corresponding effect on pre-tax income from continuing operations of approximately $167 million and $143 million, respectively over the next 12 months. Comparatively, a fifteen cent price change sensitivity analysis as of December 31, 2005 would have impacted pre-tax income from continuing operations by approximately $105 million over the next 12 months. The increase is due primarily to the NGL production after December 31, 2006 being included in the June 30, 2006 sensitivity which is currently not hedged.

Normal Purchases and Normal Sales . During 2005, the Board of Directors of Duke Energy authorized and directed management to execute the sale or disposition of substantially all of DENA’s remaining physical and commercial assets outside the Midwestern United States and certain contractual positions related to the Midwestern assets. As a result, Duke Energy recognized a pre-tax loss of approximately $1.9 billion in 2005 for the disqualification of its power and gas forward sales contracts previously designated under the normal purchases normal sales exception. This loss is partially offset by the recognition of a pre-tax gain of approximately $1.2 billion for the discontinuance of hedge accounting for natural gas and power cash flow hedges. Duke Energy retained the Midwestern generation assets of DENA, representing approximately 3,600 megawatts of power generation and combined them with Cinergy’s commercial operations in the Midwest (see Note 2 to the Consolidated Financial Statements, “Acquisitions and Dispositions,” for further details on the Cinergy merger).

Trading and Undesignated Portfolio Risk. Duke Energy’s current energy marketing and trading activities principally consist of the Cinergy commercial marketing and trading business’ natural gas marketing and trading operations and CG&E’s power marketing and trading operations. In June 2006, Duke Energy announced it had reached an agreement to sell the Cinergy marketing and trading business (see Note 13 to the Consolidated Financial Statements, “Discontinued Operations and Assets Held for Sale”). The sale is anticipated to close in the third quarter of 2006.

Duke Energy’s domestic operations market and trade over-the-counter (an informal market where the buying/selling of commodities occurs) contracts for the purchase and sale of electricity (primarily in the midwest region of the United States), natural gas, and other energy-related products, including coal and emission allowances. Duke Energy’s natural gas domestic operations provide services that manage storage, transportation, gathering and processing activities. In addition, Duke Energy’s domestic operations market and trade natural gas and other energy-related products on the New York Mercantile Exchange.

Natural gas marketing and trading operations also extend to Canada where natural gas marketing and management services are provided to producers and industrial customers. Duke Energy’s Canadian operations also market and trade over-the-counter contracts as well as energy-related products on the New York Mercantile Exchange.

Many of these energy commodity contracts commit Duke Energy to purchase or sell electricity, natural gas, and other energy-related products at fixed prices in the future. The majority of the contracts in the natural gas and other energy-related products portfolios are financially settled contracts

PART I

(i.e., there is no physical delivery related with these items). Duke Energy’s risk management policies contain limits associated with the overall size of net open positions for each trading operation.

Once Duke Energy completes its announced exit from the Cinergy commercial marketing and trading business (which have been classified as discontinued operations), its exposure to movements in the price of electricity and other energy commodities will be reduced and, as a result, may lead to decreased future earnings volatility.

Duke Energy currently measures the market risk inherent in the trading portfolio, employing value at risk (VaR) analysis and other methodologies, which utilize forward price curves in electric power and natural gas markets to quantify estimates of the magnitude and probability of future value changes related to open contract positions. Subsequent to the merger with Cinergy, Duke Energy adopted a VaR methodology for disclosure purposes, in line with how Duke Energy currently manages the portfolio. VaR is a statistical measure used to quantify the potential change in the economic value of the trading portfolio over a particular period of time, with a specified likelihood of occurrence, due to market movement. Duke Energy, through some of its non-regulated subsidiaries, markets and trades physical natural gas and electricity and trades derivative commodity instruments which are usually settled in cash including: forwards, futures, swaps, and options.

Any proprietary trading transaction, whether settled physically or financially, is included in the VaR calculation. VaR is reported based on a 95 percent confidence interval, utilizing a one-day holding period. This means that on a given day (one-day holding period) there is a 95 percent chance (confidence level) that Duke Energy’s trading portfolio will not lose more than the stated amount. VaR is measured using a Monte Carlo simulation methodology that considers implied forward-looking volatilities and historical 21 day correlations. Duke Energy’s VaR amounts for commodity derivatives recorded using the mark-to-market model of accounting are shown in the following table.

Value at Risk


	June 30, 2006 One-Day Impact on Pre-tax Income from Continuing Operations for 2006	Estimated Average One-Day Impact on Pre-tax Income from Continuing Operations for Second Quarter 2006	High One-Day Impact on Pre-tax Income from Continuing Operations for Second Quarter 2006	Low One-Day Impact on Pre-tax Income from Continuing Operations for Second Quarter 2006
	(in millions)
Calculated VaR	$5	$5	$13	$2

(1)	The VaR figures above do not include the hedges which were de-designated as a result of the transfer of 19.7% of Duke Energy’s interest in DEFS to ConocoPhillips, (see Note 15 to the Consolidated Financial Statements, “Risk Management Instruments”).

(2)	DENA VaR at June 30, 2006 was not material.

Duke Energy historically used daily earnings at risk (DER) to measure and monitor the mark-to-market portfolio’s impact on earnings. DER computations are based on historical simulation, which uses price movements over an eleven day period. The historical simulation emphasizes the most recent market activity, which is considered the most relevant predictor of immediate future market movements for natural gas, electricity and other energy-related products. DER computations use several key assumptions, including a 95% confidence level for the resultant price movement and the holding period specified for the calculation.

Duke disclosed a DER of $12 million as of December 31, 2005. This was primarily comprised of DENA derivative positions. DENA’s DER at June 30, 2006 was zero due to the DENA wind-down. The DER figures do not include the hedges which were de-designated as a result of the transfer of 19.7% of Duke Energy’s interest in DEFS to ConocoPhillips. The calculated consolidated DER at December 31, 2005 consists of approximately $11 million related to discontinued operations and less than $1 million related to continuing operations.

Duke Energy Trading & Marketing (“DETM”), the 60%/40% unregulated joint venture with Exxon Mobil continues to prudently manage down its legacy natural gas positions. While the venture was originally created to actively trade and market natural gas following de-regulation, the venture is a very different business today. No active trading is occurring now other than transacting to meet contractual obligations and to optimize remaining legacy gas positions. These legacy positions do not generate any material earnings volatility for Duke Energy.

Generation Portfolio Risks. Duke Energy optimizes the value of its non-regulated portfolio. The portfolio includes generation assets (power and capacity), fuel, and emission allowances. Modeled forecasts of future generation output, fuel requirements, and emission allowance requirements are based on forward power, fuel and emission allowance markets. The component pieces of the portfolio are bought and sold based on this model in order to manage the economic value of the portfolio. With the issuance of SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities” (SFAS 149), most forward power transactions and certain coal transactions from management of the portfolio are accounted for at fair value. The other component pieces of the portfolio are typically not subject to SFAS 149 and are accounted for using the accrual method, where changes in fair value are not recognized. As a result, these forward sales and purchases are subject to earnings volatility via mark-to-market gains or losses from changes in the value of the contracts accounted for using fair value. In

PART I

addition, the generation portfolio not utilized to serve native load or committed load is subject to commodity price fluctuations. This is primarily related to the Midwestern generation assets retained from DENA. A spark spread sensitivity on these MWH was immaterial at June 30, 2006.

Credit Risk

Credit risk represents the loss that Duke Energy would incur if a counterparty fails to perform under its contractual obligations. To reduce credit exposure, Duke Energy seeks to enter into payment netting agreements with counterparties that permit Duke Energy to offset receivables and payables with such counterparties. Duke Energy attempts to further reduce credit risk with certain counterparties by entering into agreements that enable Duke Energy to obtain collateral or to terminate or reset the terms of transactions after specified time periods or upon the occurrence of credit-related events. Duke Energy may, at times, use credit derivatives or other structures and techniques to provide for third-party credit enhancement of Duke Energy’s counterparties’ obligations.

Duke Energy’s principal customers for power and natural gas marketing and transportation services are industrial end-users, marketers, local distribution companies and utilities located throughout the U.S., Canada and Latin America. Duke Energy has concentrations of receivables from natural gas and electric utilities and their affiliates, as well as industrial customers and marketers throughout these regions. These concentrations of customers may affect Duke Energy’s overall credit risk in that risk factors can negatively impact the credit quality of the entire sector. Where exposed to credit risk, Duke Energy analyzes the counterparties’ financial condition prior to entering into an agreement, establishes credit limits and monitors the appropriateness of those limits on an ongoing basis.

In 1999, the Industrial Development Corp of the City of Edinburg, Texas (IDC) issued approximately $100 million in bonds to purchase equipment for lease to Duke Hidalgo (Hidalgo), a subsidiary of Duke Capital. Duke Capital unconditionally and irrevocably guaranteed the lease payments of Hidalgo to IDC through 2028. In 2000, Hidalgo was sold to Calpine Corporation and Duke Capital remained obligated under the lease guaranty. In January 2006, Hidalgo and its subsidiaries filed for bankruptcy protection in connection with the previous bankruptcy filing by its parent, Calpine Corporation in December 2005. Gross exposure under the guarantee obligation as of June 30, 2006 is approximately $200 million, which includes principal and interest. Duke Energy does not believe a loss under the guarantee obligation is probable as of June 30, 2006, but continues to evaluate the situation. Therefore, no reserves have been recorded for any contingent loss as of June 30, 2006. No demands for payment of principal or interest have been made under the guarantee. If future losses are incurred under the guarantee, Duke Capital has certain rights which should allow it to mitigate such loss.

Item 4. Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

Disclosure controls and procedures are controls and other procedures that are designed to ensure that information required to be disclosed by Duke Energy in the reports it files or submits under the Securities Exchange Act of 1934 (Exchange Act) is recorded, processed, summarized, and reported, within the time periods specified by the Securities and Exchange Commission’s (SEC) rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to provide reasonable assurance that information required to be disclosed by Duke Energy in the reports it files under the Exchange Act is accumulated and communicated to management, including the chief executive officer and chief financial officer, as appropriate to allow timely decisions regarding required disclosure.

Under the supervision and with the participation of management, including the chief executive officer and chief financial officer, Duke Energy has evaluated the effectiveness of its disclosure controls and procedures (as such term is defined in Rule 13a-15(e) and 15d-15(e) under the Exchange Act) as of June 30, 2006, and, based upon this evaluation, the chief executive officer and chief financial officer have concluded that these controls and procedures are effective in providing reasonable assurance that information requiring disclosure is recorded, processed, summarized, and reported within the timeframe specified by the SEC’s rules and forms.

Changes in Internal Control over Financial Reporting

Under the supervision and with the participation of management, including the chief executive officer and chief financial officer, Duke Energy has evaluated changes in internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that occurred during the fiscal quarter ended June 30, 2006 and, other than the Duke Energy and Cinergy merger discussed below, found no change that has materially affected, or is reasonably likely to materially affect, internal control over financial reporting.

On April 3, 2006, the previously announced merger between Duke Energy and Cinergy was consummated. Duke Energy is currently in the process of integrating Cinergy’s operations and will be conducting control reviews pursuant to Section 404 of the Sarbanes-Oxley Act of 2002. See Notes 1, 2 and 14 to the Consolidated Financial Statements for additional information relating to the merger.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

For information regarding legal proceedings that became reportable events or in which there were material developments in the second quarter of 2006, see Note 16 to the Consolidated Financial Statements, “Regulatory Matters” and Note 17 to the Consolidated Financial Statements, “Commitments and Contingencies.”

Item 1A. Risk Factors

In addition to the other information set forth in this report, careful consideration should be given to the factors discussed in Part I, “Item 1A. Risk Factors” in Duke Energy’s and Cinergy’s Annual Reports on Form 10-K for the year ended December 31, 2005, as have been updated in Duke Energy’s Quarterly Report on Form 10-Q for the period ended March 31, 2006, which could materially affect Duke Energy’s financial condition or future results. Additional risks and uncertainties not currently known to Duke Energy or that Duke Energy correctly deems to be immaterial also may materially adversely affect Duke Energy’s financial condition and/or results of operations.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

Issuer Purchases of Equity Securities for Second Quarter of 2006


Period	Total Number of Shares (or Units) Purchased ^a	Average Price Paid per Share (or Unit)		Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs ^a	Approximate Dollar Value of Shares (or Units) that May Yet Be Purchased Under Plans or Programs ^a (in billions)
April 1 to April 30	4,067,400	$	28.97	4,067,400	$	1.4
May 1 to May 31	6,246,200	$	28.13	6,246,200	$	1.2
June 1 to June 30	4,777,000	$	28.56	4,777,000	$	1.1

Duke Energy previously announced plans to execute up to approximately $2.5 billion in common stock repurchases over a three year period. On May 9, 2005, Duke Energy announced plans to suspend additional repurchases under the open-market purchase plan, pending further assessment, primarily due to the merger with Cinergy. At the time of suspension, Duke Energy had repurchased 32.6 million shares of common stock for approximately $0.9 billion. During the first quarter of 2006, Duke Energy announced the commencement of up to $1 billion of additional share repurchases under the previously announced plan. During the three month period ended June 30, 2006, Duke Energy repurchased approximately 15.1 million shares for approximately $0.4 billion (see Note 4 to the Consolidated Financial Statements, “Common Stock”). Through June 30, 2006, Duke Energy has repurchased approximately 50 million shares of common stock for approximately $1.4 billion under this repurchase plan. In connection with the plan to spin off Duke Energy’s natural gas business to Duke Energy shareholders, the share repurchase program has since been suspended.

Item 4. Submission of Matters to a Vote of Security Holders

No matters were submitted to a vote of Duke Energy’s security holders during the second quarter of 2006.

PART II

Item 6. Exhibits

(a) Exhibits

Exhibits filed or furnished herewith are designated by an asterisk (*). All exhibits not so designated are incorporated by reference to a prior filing, as indicated. Items constituting management contracts or compensatory plans or arrangements are designated by a double asterisk (**).


Exhibit Number
3.1		Amended and Restated Certificate of Incorporation (filed with Form 8-K of registrant, File No. 1-32853, April 4, 2006, as exhibit 3.1)

3.2		Amended and Restated By-Laws (filed with Form 8-K of registrant, File No. 1-32853, April 4, 2006, as exhibit 3.2)

*10.1		Fifteenth Supplemental Indenture, dated as of April 3, 2006, among the registrant, Duke Energy and JPMorgan Chase Bank, N.A. (as successor to Guaranty Trust Company of New York), as trustee (the “Trustee”), supplementing the Senior Indenture, dated as of September 1, 1998, between Duke Power Company LLC (formerly Duke Energy Corporation) and the Trustee

10.3		Amendment to Purchase and Sale Agreement, dated as of May 4, 2006, by and among Duke Energy Americas, LLC, LS Power Generation, LLC (formerly known as LSP Bay II Harbor Holding, LLC), LSP Gen Finance Co, LLC, LSP South Bay Holdings, LLC, LSP Oakland Holdings, LLC, and LSP Morro Bay Holdings, LLC

10.4**		Form of Phantom Stock Award Agreement (filed with Form 8-K of Duke Energy Corporation, File No. 1-32853, April 4, 2006, as exhibit 10.1)

10.5**		Form of Performance Share Award Agreement (filed with Form 8-K of Duke Energy Corporation, File No. 1-32853, April 4, 2006, as exhibit 10.2)

10.6**		Employment Agreement between Duke Energy Corporation and James E. Rogers, dated April 4, 2006 (filed with Form 8-K of Duke Energy Corporation, File No. 1-32853, April 6, 2006, as exhibit 10.1)

10.7**		Performance Award Agreement between Duke Energy Corporation and James E. Rogers, dated April 4, 2006 (filed with Form 8-K of Duke Energy Corporation, File No. 1-32853, April 6, 2006, as exhibit 10.2)

10.8**		Phantom Stock Grant Agreement between Duke Energy Corporation and James E. Rogers, dated April 4, 2006 (filed with Form 8-K of Duke Energy Corporation, File No. 1-32853, April 6, 2006, as exhibit 10.3)

10.9**		Stock Option Grant Agreement between Duke Energy Corporation and James E. Rogers, dated April 4, 2006 (filed with Form 8-K of Duke Energy Corporation, File No. 1-32853, April 6, 2006, as exhibit 10.4)

10.10**		Second Amendment to Employment Agreement, dated as of April 4, 2006, by and among Paul M. Anderson, Duke Energy Holding Corp. (subsequently renamed Duke Energy Corporation) and Duke Energy Corporation (subsequently renamed Duke Power LLC) (filed with Form 8-K of Duke Energy Corporation, File No. 1-32853, April 6, 2006, as exhibit 10.5)

10.11**		Retention Award Agreement between Duke Energy Corporation and David L. Hauser, dated April 4, 2006 (filed with Form 8-K of Duke Energy Corporation, File No. 1-32853, April 6, 2006, as exhibit 10.6)

10.12**		Severance and Retention Agreement between Duke Energy Corporation and Ruth Shaw, dated April 4, 2006 (filed with Form 8-K of Duke Energy Corporation, File No. 1-32853, April 6, 2006, as exhibit 10.7)

10.13*		Summary of Director Compensation

10.14**		Form Phantom Stock Award Agreement and Election to Defer (filed with Form 8-K of Duke Energy Corporation, File No. 1-32853, May 16, 2006, as exhibit 10.1)

*10.15		Agreements with Piedmont Electric Membership Corporation, Rutherford Electric Membership Corporation and Blue Ridge Electric Membership Corporation to provide wholesale electricity and related power scheduling services from September 1, 2006 through December 31, 2021

PART II


Exhibit Number
10.16		Agreement with Dynegy Inc. and Rockingham Power, L.L.C. to acquire an approximately 825 megawatt power plant located in Rockingham County, N.C. for approximately $195 million (filed with Form 8-K of Duke Energy Corporation, File No. 1-32853, May 25, 2006, as exhibit 10.1)

10.17		Purchase and Sale Agreement by and among Cinergy Capital & Trading, Inc., as Seller, and Fortis Bank, S.A./N.V., as Buyer, dated as of June 26, 2006 (filed with Form 8-K of Duke Energy Corporation, File No. 1-32853, June 30, 2006, as exhibit 10.1)

*10.18		Amended and Restated Credit Agreement, dated June 29, 2006, among Cinergy Corp., CG&E, PSI, ULH&P, The Banks Listed Herein, Barclays Bank PLC, as Administrative Agent, and JPMorgan Chase Bank, N.A., as Syndication Agent.

*10.19		Amended and Restated Credit Agreement, dated June 29, 2006, among Duke Capital LLC, The Banks Listed Herein, JPMorgan Chase Bank, N.A., as Administrative Agent, and Wachovia Bank, National Association, as Syndication Agent.

*10.20		Amended and Restated Credit Agreement, dated June 29, 2006, among Duke Power Company LLC, The Banks Listed Herein, Citibank N.A., as Administrative Agent, and Banc of America, N.A., as Syndication Agent.

*31.1		Certification of the Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

*31.2		Certification of the Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

*32.1		Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

*32.2		Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

The total amount of securities of the registrant or its subsidiaries authorized under any instrument with respect to long-term debt not filed as an exhibit does not exceed 10% of the total assets of the registrant and its subsidiaries on a consolidated basis. The registrant agrees, upon request of the Securities and Exchange Commission, to furnish copies of any or all of such instruments to it.

PART II

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


				DUKE ENERGY CORPORATION

Date: August 9, 2006				/s/ D AVID L. H AUSER
				David L. Hauser Group Executive and Chief Financial Officer

Date: August 9, 2006				/s/ S TEVEN K. Y OUNG
				Steven K. Young Vice President and Controller

Exhibit 10.1

FIFTEENTH SUPPLEMENTAL INDENTURE

T HIS F IFTEENTH S UPPLEMENTAL I NDENTURE , dated as of April 3, 2006 (the “Fifteenth Supplemental Indenture”), among Duke Energy Corporation, a North Carolina corporation (“Duke Energy”), Duke Energy Holding Corp., a Delaware corporation (formerly named Deer Holding Corp.) (“Duke Holdco”) and JPMorgan Chase Bank, N.A. (formerly known as The Chase Manhattan Bank), a national banking association, as trustee under the Indenture referred to below (the “Trustee”).

W I T N E S S E T H

WHEREAS, Duke Energy has heretofore entered into the Senior Indenture, dated as of September 1, 1998 (the “Original Indenture”), with the Trustee, as supplemented to the date hereof (as so supplemented, the “Indenture”);

WHEREAS, Duke Energy currently has issued and Outstanding the notes of the series listed on Schedule A hereto (collectively, the “Notes”) under the Indenture;

WHEREAS, on May 3, 2005, Duke Energy incorporated Duke Holdco as a direct, wholly-owned subsidiary of Duke Energy, and Duke Holdco incorporated Deer Acquisition Corp., a North Carolina corporation (“Merger Sub A”), and Cougar Acquisition Corp., a Delaware corporation (“Merger Sub B”), each as a direct, wholly-owned subsidiary of Duke Holdco;

WHEREAS, Duke Energy entered into the Agreement and Plan of Merger, dated as of May 8, 2005, as amended (the “Merger Agreement”), by and among Duke Energy, Cinergy Corp., a Delaware corporation (“Cinergy”), Duke Holdco, Merger Sub A and Merger Sub B, providing for the consummation of the business combination contemplated therein;

WHEREAS, pursuant to the terms of the Merger Agreement, Merger Sub A shall merge with and into Duke Energy (the “Duke Energy Merger”), in accordance with the North Carolina Business Corporation Act (“NCBCA”), whereby Duke Energy shall be the surviving corporation in the Duke Energy Merger and shall continue its existence under the laws of the State of North Carolina and shall succeed to and assume all the rights and obligations of Merger Sub A in accordance with the NCBCA and, as a result of the Duke Energy Merger, shall be a direct, wholly-owned subsidiary of Duke Holdco;

WHEREAS, following effectiveness of the Duke Energy Merger, Duke Energy shall convert its form of organization into a limited liability company pursuant to a plan of conversion adopted pursuant to Section 55-11A-11 of the NCBCA and Section 57C-9A-02 of the North Carolina Limited Liability Company Act and shall be renamed Duke Power Company LLC, all of whose membership or other equity interests shall be held by Duke Holdco (the “Duke Energy Conversion” and, together with the Duke Energy Merger, the “Duke Energy Reorganization”);

WHEREAS, Duke Energy is currently the direct owner of 100% of the issued and outstanding equity interests of Duke Capital LLC, a Delaware limited liability company (“Duke Capital”);

WHEREAS, following effectiveness of the Duke Energy Reorganization, Duke Energy shall distribute to Duke Holdco all the issued and outstanding equity interests of Duke Capital (the “Duke Capital Distribution”) and, as a result, each of Duke Energy and Duke Capital shall be a direct, wholly-owned subsidiary of Duke Holdco;

WHEREAS, in connection with the Duke Capital Distribution, Duke Holdco desires to fully and unconditionally guarantee the payment obligations of Duke Energy with respect to the Notes as long as the Notes remain Outstanding;

WHEREAS, Section 901(9) of the Original Indenture provides, among other things, that Duke Energy, when authorized by a Board Resolution, and the Trustee, at any time and from time to time, may enter into an indenture supplemental to the Original Indenture for the purpose of making any provisions with respect to matters arising under the Indenture, provided that such action does not adversely affect the interests of the Holders of Securities of any series in any material respect;

WHEREAS, the execution of the Fifteenth Supplemental Indenture is authorized and permitted by Section 901 of the Original Indenture and all conditions precedent provided for in the Indenture relating to the execution of the Fifteenth Supplemental Indenture have been complied with; and

WHEREAS, this Fifteenth Supplemental Indenture is being executed prior to the closing of the transactions contemplated by the Merger Agreement, including the Duke Energy Merger and the Duke Energy Reorganization, and shall be effective simultaneously with the Duke Capital Distribution.

NOW, THEREFORE, in consideration of the foregoing and for other good and valuable consideration, the receipt of which is hereby acknowledged, Duke Energy, Duke Holdco and the Trustee mutually covenant and agree for the equal and ratable benefit of the Holders from time to time of the Notes (the “Holders”) as follows:

S ECTION 101. Capitalized Terms . Capitalized terms used herein without definition shall have the meanings assigned to them in the Original Indenture.

S ECTION 102. Guarantee . Duke Holdco does hereby fully and unconditionally guarantee for the benefit of the Holders and the Trustee (the “Guarantee”) (a) the due and punctual payment of the principal of, premium, if any, and interest on, all the Notes, whether at Stated Maturity, by declaration of acceleration, call for redemption or otherwise, the due and punctual payment of interest on overdue principal of, premium, if any, and interest on all the Notes, if any, if lawful, and the due and punctual performance of all other obligations of Duke Energy to the Holders or the Trustee in accordance with the terms of the Indenture, and (b) in case of any extension of time of payment or renewal of any Notes or any such other obligations, that the same will be promptly paid in full when due or performed in accordance with the terms of the extension or renewal, whether at stated maturity, by acceleration or otherwise.

In case of the failure of Duke Energy to punctually make any such principal, premium, if any, or interest payment, Duke Holdco hereby agrees to cause any such payment to be made promptly when and as the same shall become due and payable, whether at Stated Maturity, by declaration of acceleration, call for redemption or otherwise, and as if such payment were made by Duke Energy.

Duke Holdco hereby agrees that its obligations under the Guarantee shall be as if it were principal debtor and not merely surety, and shall be absolute and unconditional, irrespective of, and shall be unaffected by, any invalidity, irregularity or unenforceability of any Note of any series or the Indenture, any failure to enforce the provisions of any Note of any series or this Indenture, or any waiver, modification or indulgence granted to Duke Energy with respect thereto, by the Holder of any Note of any series or the Trustee, or any other circumstance which may otherwise constitute a legal or equitable discharge of a surety or guarantor; provided, however, that, notwithstanding the foregoing, no such waiver, modification or indulgence shall, without the consent of Duke Holdco, increase the principal amount of a Note or the interest rate thereon or increase any premium payable upon redemption thereof. Duke Holdco hereby waives diligence, presentment, demand of payment, filing of claims with a court in

the event of a merger or bankruptcy of Duke Energy, any right to require a proceeding first against Duke Energy, protest or notice with respect to any Note or the indebtedness evidenced thereby or with respect to any sinking fund payment required pursuant to the terms of a Note issued under the Indenture and all demands whatsoever, and covenants that the Guarantee will not be discharged with respect to any Note except by payment in full of the principal of (and premium, if any) and interest on such Note. The Guarantee shall constitute a guarantee of payment and not of collection and shall not be impaired by the failure to endorse evidence of the Guarantee on any Note.

Duke Holdco shall be subrogated to all rights of the Holder of a Note against Duke Energy in respect of any amounts paid to such Holder by Duke Holdco pursuant to the provisions of the Guarantee; provided, however, that Duke Holdco shall not be entitled to enforce, or to receive any payments arising out of or based upon, such right of subrogation until the principal of (and premium, if any) and interest on all Notes of the relevant series shall have been paid in full.

S ECTION 103. Limitation on Liens . Duke Holdco will not, while any of the Notes remains Outstanding, create or suffer to be created or to exist, any mortgage, lien, pledge, security interest or other encumbrance of any kind upon any property of Duke Holdco, whether now owned or hereafter acquired, to secure any indebtedness for borrowed money of Duke Holdco, unless it shall make effective provisions whereby the Notes then Outstanding shall be secured by such mortgage, lien, pledge, security interest or other encumbrance equally and ratably with any and all indebtedness for borrowed money thereby secured so long as any such indebtedness shall be so secured; provided, however , that nothing in this Section shall be construed to prevent Duke Holdco from creating, or from suffering to be created or to exist, any mortgages, liens, pledges, security interests or other encumbrances, or any agreements, with respect to:

(1) purchase money mortgages, or other purchase money liens, pledges, security interests or encumbrances of any kind upon property hereafter acquired by Duke Holdco, or mortgages, liens, pledges, security interests or other encumbrances of any kind existing on any property at the time of the acquisition thereof (including mortgages, liens, pledges, security interests or other encumbrances which exist on any property of a Person which is consolidated with or merged with or into Duke Holdco or which transfers or leases all or substantially all of its properties to Duke Holdco), or conditional sales agreements or other title retention agreements and leases in the nature of title retention agreements with respect to any property hereafter acquired; provided, however , that no such mortgage, lien, pledge, security interest or other encumbrance shall extend to or cover any other property of Duke Holdco;

(2) mortgages, liens, pledges, security interests or other encumbrances of any kind upon any property of Duke Holdco existing as of the date of the Fifteenth Supplemental Indenture; liens for taxes or assessments or other governmental charges or levies; pledges or deposits to secure obligations under worker’s compensation laws, unemployment insurance and other social security legislation, including liens of judgments thereunder which are not currently dischargeable; pledges or deposits to secure performance in connection with bids, tenders, contracts (other than contracts for the payment of money) or leases to which Duke Holdco is a party; pledges or deposits to secure public or statutory obligations of Duke Holdco; builders’, materialmen’s, mechanics’, carriers’, warehousemen’s, workers’, repairmen’s, operators’, landlords’ or other like liens in the ordinary course of business, or deposits to obtain the release of such liens; pledges or deposits to secure, or in lieu of, surety, stay, appeal, indemnity, customs, performance or return-of-money bonds; other pledges or deposits for similar purposes in the ordinary course of business; liens created by or resulting from any litigation or proceeding which at the time is being contested in good faith by appropriate proceedings; liens incurred in connection with the issuance of bankers’ acceptances and lines of credit, bankers’ liens or rights of offset and any security given in the ordinary course of business to banks or others to secure any indebtedness payable on demand or maturing within 12 months of the date that such indebtedness is originally incurred; liens incurred in connection with repurchase, swap or other similar agreements (including, without limitation, commodity price,

currency exchange and interest rate protection agreements); leases made, or existing on property acquired, in the ordinary course of business; liens securing industrial revenue or pollution control bonds; liens, pledges, security interests or other encumbrances on any property arising in connection with any defeasance, covenant defeasance or in-substance defeasance of indebtedness of Duke Holdco, including its guarantee obligations in respect of the Notes; liens created in connection with, and created to secure, a non-recourse obligation; zoning restrictions, easements, licenses, rights-of-way, restrictions on the use of property or minor irregularities in title thereto, which do not, in the opinion of Duke Holdco, materially impair the use of such property in the operation of the business of Duke Holdco or the value of such property for the purpose of such business;

(3) First and Refunding Mortgage Bonds of the Corporation issued or to be issued from time to time under the First and Refunding Mortgage dated as of December 1, 1927 from the Corporation to the trustee named therein, as supplemented and amended and as to be supplemented and amended;

(4) indebtedness which may be issued by Duke Holdco in connection with a consolidation or merger of Duke Holdco with or into any other Person (which may be an Affiliate of Duke Holdco) in exchange for or otherwise in substitution for secured indebtedness of such Persons (“Third Party Debt”) which by its terms (i) is secured by a mortgage on all or a portion of the property of such Person, (ii) prohibits secured indebtedness from being incurred by such Person, unless the Third Party Debt shall be secured equally and ratably with such secured indebtedness or (iii) prohibits secured indebtedness from being incurred by such Person;

(5) indebtedness of any Person which is required to be assumed by Duke Holdco in connection with a consolidation or merger of such Person, with respect to which any property of Duke Holdco is subjected to a mortgage, lien, pledge, security interest or other encumbrance;

(6) mortgages, liens, pledges, security interests or other encumbrances of any kind upon any property acquired, constructed, developed, or improved by Duke Holdco (whether alone or in association with others) after the date of this Fifteenth Supplemental Indenture which are created prior to, at the time of, or within 18 months after such acquisition (or in the case of property constructed, developed or improved, after the completion of such construction, development or improvement and commencement of full commercial operation of such property, whichever is later) to secure or provide for the payment of any part of the purchase price or cost thereof; provided that in the case of such construction, development or improvement the mortgages, liens, pledges, security interests or other encumbrances shall not apply to any property theretofore owned by Duke Holdco other than theretofore unimproved real property;

(7) Mortgages, liens, pledges, security interests or other encumbrances permitted to be incurred by Duke Energy and Cinergy and their respective subsidiaries pursuant to their respective debt instruments outstanding on the date hereof;

(8) the replacement, extension or renewal (or successive replacements, extensions or renewals), as a whole or in part, of any mortgage, lien, pledge, security interest or other encumbrance, or of any agreement, referred to above in clauses (1) through (7) inclusive, or the replacement, extension or renewal (not exceeding the principal amount of indebtedness secured thereby together with any premium, interest, fee or expense payable in connection with any such replacement, extension or renewal) of the indebtedness secured thereby; provided that such replacement, extension or renewal is limited to all or a part of the same property that secured the mortgage, lien, pledge, security interest or other encumbrance replaced, extended or renewed (plus improvements thereon or additions or accessions thereto); or

(9) any other mortgage, lien, pledge, security interest or other encumbrance not excepted by the foregoing clauses (1) through (8); provided that immediately after the creation or assumption of such mortgage, lien, pledge, security interest or other encumbrance, the aggregate principal amount of indebtedness for borrowed money of Duke Holdco secured by all mortgages, liens, pledges, security

interests and other encumbrances created or assumed under the provisions of this clause (9) shall not exceed an amount equal to 10% of common stockholders’ equity of Duke Holdco as shown on its consolidated balance sheet for the accounting period occurring immediately prior to the creation or assumption of such mortgage, lien, pledge, security interest or other encumbrance.

This Section 103 shall be for the sole benefit of the Notes and not for the benefit of any future series of Securities Outstanding under the Indenture unless Duke Holdco agrees otherwise.

S ECTION 104. Duke Holdco May Consolidate, Etc., on Certain Terms . (1) Nothing contained in the Indenture, this Fifteenth Supplemental Indenture or in any of the Notes shall prevent any consolidation or merger of Duke Holdco with or into any other Person or Persons (whether or not affiliated with Duke Holdco), or successive consolidations or mergers in which Duke Holdco or its successor or successors shall be a party or parties, or shall prevent any conveyance or transfer of the properties and assets of Duke Holdco as an entirety or substantially as an entirety to any other Person (whether or not affiliated with Duke Holdco) lawfully entitled to acquire the same; provided, however , and Duke Holdco hereby covenants and agrees, that upon any such consolidation, merger, conveyance or transfer, (i) the obligations of Duke Holdco as set forth in Section 102 herein shall be expressly assumed, by a supplemental indenture, in form reasonably satisfactory to the Trustee, executed and delivered to the Trustee by the Person (if other than Duke Holdco) formed by such consolidation, or into which Duke Holdco shall have been merged, or by the Person which shall have acquired such properties and assets and (ii) Duke Holdco shall deliver to the Trustee an Officers’ Certificate and an Opinion of Counsel, each stating that such consolidation, merger, conveyance or transfer and, if a supplemental indenture is required in connection with such transaction, such supplemental indenture, comply with this Section and that all conditions precedent herein provided for relating to such transaction have been complied with.

Solely for the purpose of clause (ii) of this Section 104(1), the term “Corporation,” appearing in the definition of the term “Officers’ Certificate” in Section 101 of the Original Indenture, shall be changed to “Duke Holdco.”

(2) Upon any consolidation of Duke Holdco with, or merger of Duke Holdco into, any other Person or any conveyance or transfer of the properties and assets of Duke Holdco as an entirety or substantially as an entirety in accordance with this Section, the successor Person formed by such consolidation or into which Duke Holdco is merged or to which such conveyance or transfer is made shall succeed to, and be substituted for, and may exercise every right and power of, Duke Holdco under this Fifteenth Supplemental Indenture and the Indenture with the same effect as if such successor Person had been named as Duke Holdco herein, and thereafter the predecessor Person shall be relieved of all obligations and covenants under this Fifteenth Supplemental Indenture, the Indenture and the Notes.

This Section 104 shall be for the sole benefit of the Notes and not for the benefit of any future series of Securities Outstanding under the Indenture unless Duke Holdco agrees otherwise.

S ECTION 105. Miscellaneous Amendments .

(1) Section 102 of the Original Indenture is hereby amended by adding the following definition:

“Duke Holdco” means Duke Energy Holding Corp., a Delaware corporation (formerly named Deer Holding Corp.).

(2) Section 105 of the Original Indenture is hereby amended by deleting “or” after clause (1) thereof, by deleting the period after clause (2) thereof and inserting “, or” in its place and by adding the following clause (3):

“(3) Duke Holdco by the Trustee or by any Holder shall be sufficient for every purpose hereunder (unless otherwise herein expressly provided) if in writing and mailed, first-class postage prepaid, to Duke Holdco addressed to it at 526 South Church Street, Charlotte, North Carolina 28202, Attention: Treasurer, or at any other address previously furnished in writing to the Trustee by Duke Holdco.”;

(3) Section 501(4) of the Original Indenture is hereby amended to read as follows:

“(4) default in the performance, or breach, of any covenant of the Corporation or Duke Holdco in this Indenture (other than a covenant a default in whose performance or whose breach is elsewhere in this Section specifically dealt with or which has expressly been included in this Indenture solely for the benefit of series of Securities other than that series), and continuance of such default or breach for a period of 90 days after there has been given, by registered or certified mail, to the Corporation or Duke Holdco, as the case may be, by the Trustee or to the Corporation or Duke Holdco, as the case may be, and the Trustee by the Holders of at least 33% in principal amount of the Outstanding Securities of that series a written notice specifying such default or breach and requiring it to be remedied and stating that such notice is a “Notice of Default” hereunder, unless the Trustee, or the Trustee and the Holders of a principal amount of Securities of such series not less than the principal amount of Securities the Holders of which gave such notice, as the case may be, shall agree in writing to an extension of such period prior to its expiration; provided, however, that the Trustee, or the Trustee and the Holders of such principal amount of Securities of such series, as the case may be, shall be deemed to have agreed to an extension of such period if corrective action is initiated by the Corporation or Duke Holdco, as the case may be, within such period and is being diligently pursued; or” and

(4) Section 704 of the Original Indenture is hereby amended to read as follows:

The Corporation, or Duke Holdco (if the Corporation’s obligation to file separate reports to the Commission pursuant to the Trust Indenture Act or Section 13 or Section 15(d) of the Exchange Act shall be terminated or expressly assumed by Duke Holdco), shall file with the Trustee and the Commission, and transmit to Holders, such information, documents and other reports, and such summaries thereof, as may be required pursuant to the Trust Indenture Act at the times and in the manner provided pursuant to such Act; provided that any such information, documents or reports required to be filed with the Commission pursuant to Section 13 or Section 15(d) of the Exchange Act shall be filed with the Trustee within 15 days after the same is so required to be filed with the Commission.

(5) Section 901(1) of the Original Indenture is hereby amended to read as follows:

“(1) to evidence the succession of another person to the Corporation or Duke Holdco, as the case may be, and the assumption by any such successor of the covenants of, respectively, the Corporation or Duke Holdco herein and in the Securities; or”.

This Section 105 shall be for the sole benefit of the Notes and not for the benefit of any future series of Securities Outstanding under the Indenture unless Duke Holdco agrees otherwise.

S ECTION 106. No Recourse Against Others . No past, present or future director, officer, employee, incorporator, stockholder, partner or agent of Duke Holdco shall have any liability for any obligations of Duke Energy or Duke Holdco under the Notes, the Guarantee, the Indenture or the Fifteenth Supplemental Indenture or for any claim based on, in respect of, or by reason of, such obligations or their creation.

S ECTION 107. Provisions Binding on Successors . All the covenants, stipulations, premises and agreements made in the Fifteenth Supplemental Indenture by Duke Energy and Duke Holdco shall bind their respective successors and assigns whether so expressed or not.

S ECTION 108. New York Contract . THIS FIFTEENTH SUPPLEMENTAL INDENTURE AND THE GUARANTEE SHALL BE DEEMED TO BE A CONTRACT MADE UNDER THE LAWS OF THE STATE OF NEW YORK AND FOR ALL PURPOSES SHALL BE CONSTRUED IN ACCORDANCE WITH THE LAWS OF SAID STATE.

S ECTION 109. Execution and Counterparts . The Fifteenth Supplemental Indenture may be executed in any number of counterparts, each of which when so executed shall be deemed to be an original, but all such counterparts shall together constitute but one and the same instrument.

S ECTION 110. Effect of Headings . The Section headings herein are for convenience only and shall not affect the construction hereof.

S ECTION 111. The Trustee . The Trustee shall not be responsible in any manner whatsoever for or in respect of the validity or sufficiency of the Fifteenth Supplemental Indenture or for or in respect of the recitals contained herein, all of which recitals are made solely by Duke Energy and Duke Holdco.

S ECTION 112. Full Force and Effect . Except as expressly amended hereby, the Indenture shall remain in full force and effect in accordance with the provisions thereof on the date thereof.

S ECTION 113. Effectiveness of the Fifteenth Supplemental Indenture . The Fifteenth Supplemental Indenture shall be effective simultaneously with the Duke Capital Distribution. Promptly following the occurrence of the Duke Capital Distribution, Duke Energy shall provide notice thereof to the Trustee.

IN WITNESS WHEREOF, the parties hereto have caused the Fifteenth Supplemental Indenture to be duly executed, all as of the date first above written.


DUKE ENERGY CORPORATION

By:
Name:		David L. Hauser
Title:		Group Vice President and
		Chief Financial Officer

Attest:

Name:

Title:


DUKE ENERGY HOLDING CORP.

By:
Name:		Robert T. Lucas III
Title:		Assistant Secretary

Attest:

Name:

Title:


JPMORGAN CHASE BANK, N.A.,
as Trustee

By:
Name:
Title:

Attest:

Name:

Title:

Supplemental Indenture

SCHEDULE A

Outstanding Notes

•

$300,000,000 Series A 6% Senior Notes due 2028

•

$200,000,000 Series B 5 3/8% Senior Notes due 2009

•

$300,000,000 Series D 7 3/8% Senior Notes due 2010

•

$750,000,000 6.25% Senior Notes due 2012

•

$250,000,000 6.60% Insured Quarterly Senior Notes due 2022

•

$350,000,000 6.45% Senior Notes due 2032

•

$110,000,000 4.611% Senior Notes due 2007

•

$400,000,000 5.625% Senior Notes due 2012

•

$742,000,000 1 ³ / 4 % Convertible Senior Notes due 2023

•

$300,000,000 4.20% Senior Notes due 2008

Exhibit 10.13

Summary of Director Compensation


Type of Fee	Fee (Other Than for Meetings)		Meeting Fees
Type of Fee	Fee (Other Than for Meetings)		In-person Attendance at Meetings Held in Conjunction With a Regular Board Meeting		In-Person Meetings Not Held in Conjunction With a Regular Board Meeting		Telephonic Participation in Meetings
Annual Board Retainer (Cash)	$	50,000
Annual Board Retainer (Stock)	$	75,000
Board Meeting Fees			$	2,000	$	2,500	$	2,000
Annual Lead Director Retainer	$	20,000
Annual Audit Committee Chair Retainer	$	20,000
Annual Chair Retainer (Other Committees)	$	8,500
Audit Committee Meeting Fees			$	3,000	$	2,500	$	2,000
Nuclear Oversight Committee Meeting Fees			$	4,000	$	2,500	$	2,000
Other Committee Meeting Fees			$	2,000	$	2,500	$	2,000

Exhibit 10.15

PARTIAL REQUIREMENTS SERVICE AGREEMENT

BETWEEN

DUKE POWER COMPANY LLC

d/b/a DUKE ENERGY CAROLINAS, LLC

AND

PIEDMONT ELECTRIC MEMBERSHIP CORPORATION

DATED AS OF MAY 12, 2006

TABLE OF CONTENTS


			Page
Article 1 Definitions			2

	1.1	Definitions.	2

	1.2	Interpretation.	20

	1.3	Construction.	21

Article 2 Term			21

	2.1	Effectiveness.	21

	2.2	Term.	22

	2.3	Termination.	22

	2.4	Absolute Nature of Termination.	27

Article 3 Conditions Precedent to the Commencement Date			28

	3.1	Conditions Precedent to Duke’s Obligations.	28

	3.2	Conditions Precedent to EMC’s Obligations.	29

	3.3	Notice of Satisfaction of Conditions Precedent.	30

	3.4	Waiver of Condition Precedent.	30

	3.5	Commencement of Service; Failure of Condition Precedent.	30

Article 4 Sale of Electric Capacity and Energy			35

	4.1	Classification of Services Provided.	35

	4.2	FFR Supplemental Service.	35

	4.3	Partial Requirements Service.	37

	4.4	Excepted Load.	39

	4.5	Good Title.	39

	4.6	Power Quality.	39

Article 5 EMC Resources			40

	5.1	EMC Contract Resources (Commencement Date - December 31, 2010).	40

	5.2	EMC Contract Resources (January 1, 2011 - Termination of Agreement).	41

	5.3	No Duke Obligation for Customer Resources.	44

	5.4	New Customer Resources.	44

Article 6 Priority of Service			45

	6.1	Interruption of FFR Supplemental Service and Partial Requirements Service.	45


	6.2	Curtailments of Load.	45

	6.3	Emergency Load Curtailment Program.	45

	6.4	Substitute Energy.	46

	6.5	Substitute Energy Costs.	46

Article 7 Capacity and Energy Charges			46

	7.1	Charges During Commencement Date - December 31, 2006.	46

	7.2	Charges During January 1, 2007 – December 31, 2010.	51

	7.3	Charges Commencing January 1, 2011.	55

	7.4	Monthly Reserve Capacity Charges.	57

	7.5	Payment.	58

	7.6	Determination of EMC Capacity and Energy Demands.	58

Article 8 Scheduling Agent Services			59

	8.1	Appointment of Duke as Scheduling Agent.	59

	8.2	Scheduling Policies.	59

	8.3	Protocols.	59

	8.4	Scheduling Agent Services (Commencement Date through December 31, 2010).	59

	8.5	Scheduling Agent Services (January 1, 2011 through Termination).	60

	8.6	New EMC Resources.	61

	8.7	Errors in Schedules.	61

	8.8	EMC Responsibilities.	61

	8.9	Duke’s Liability.	62

	8.10	Termination Assistance Service.	62

Article 9 Transmission and Ancillary Services			62

	9.1	Delivery Obligations.	62

	9.2	Transmission Arrangements.	62

	9.3	Ancillary Services.	62

	9.4	Regional Transmission Organization.	63

Article 10 Operating Committee			64

	10.1	Operating Committee.	64

	10.2	Duties of the Operating Committee.	64



Article 11 Demand Side Management			64

	11.1	Availability of Demand Side Management Resource Programs.	64

	11.2	Changes to Demand Side Management Resource Programs.	64

	11.3	Credits.	64

	11.4	Necessary Arrangements.	65

	11.5	Start-Up Conditions.	65

	11.6	Periodic Testing.	65

	11.7	EMC Demand Side Management.	66

Article 12 Modification of This Agreement			67

	12.1	Unilateral Modification.	67

	12.2	Mobile-Sierra Public Interest Standard.	67

	12.3	Changes To Certain Charge Components.	67

	12.4	Standard of Review for Permitted Changes.	68

	12.5	Scope of Waiver.	68

Article 13 Billing and Payment			68

	13.1	Billing Period.	68

	13.2	Billing Statements.	68

	13.3	Timeliness of Payment.	69

	13.4	Netting of Payments.	69

	13.5	Disputes and Adjustments of Statements.	69

	13.6	Records and Audits.	70

Article 14 Dispute Resolution			72

	14.1	Arbitration.	72

	14.2	Negotiation and Notice of Arbitration.	72

	14.3	Individual, Joint or Consolidated Arbitration.	72

	14.4	Selection of Arbitration Process.	73

	14.5	Initiation of Arbitration.	74

	14.6	Arbitration Processes.	74

	14.7	Decision.	77

	14.8	Expenses.	78

	14.9	Effect of Dispute Resolution Procedures.	78

	14.10	Confidentiality.	78


Article 15 Credit and Collateral Requirements			78

	15.1	Posting of Collateral.	78

	15.2	Material Adverse Changes.	78

	15.3	Continuing Nature of Collateral Requirement.	79

	15.4	Interest on Cash Used as Collateral.	79

	15.5	Grant of Security Interest/Remedies.	79

	15.6	Notice, Information.	80

	15.7	Definitions.	80

Article 16 Additional Terms			82

	16.1	Representations Warranties and Covenants.	82

	16.2	Assignment.	85

	16.3	Liability and Indemnification.	86

	16.4	Force Majeure.	87

	16.5	Events of Default and Remedies.	88

	16.6	Confidential Information.	90

	16.7	Governmental Liabilities.	91

	16.8	Choice of Law.	92

	16.9	Survival of Obligations.	92

	16.10	Entire Agreement.	92

	16.11	Cost Projections.	92

	16.12	Unique Agreement.	93

	16.13	No Transfer of Rights.	93

	16.14	No Partnership.	93

	16.15	Third Parties.	93

	16.16	Waiver.	93

	16.17	Time of Essence.	93

	16.18	Headings.	94

	16.19	Severability.	94

	16.20	Counterparts.	94

	16.21	No Public Announcement.	94

	16.22	Notices.	94



16.23	No Dedication of the System.	95

16.24	Stranded Costs.	95

16.25	Electric Peak Load and Energy Information to be provided by EMC.	96

16.26	Demand and Energy Charge and Rate Information to be Provided by Duke.	96

16.27	Further Assurances.	96

16.28	Applicable Laws and Regulations.	96

16.29	Equitable Relief	96

16.30	PURPA Assistance.	96

16.31	SERC and NERC Data Reporting and Compliance Assistance.	96

SCHEDULES


1		Annual Production Capacity and Energy Rates

ATTACHMENTS
3-1		Calculation of the Excess Annual Capacity Charges in the Duke-Blue Ridge Agreement, Duke-Piedmont Agreement and Duke-Rutherford Agreement

4-1		EMC’s Base Obligation and Fixed Forward Resource

4-2		Calculation of Reduction to EMC’s Base Obligation and EMC Group’s Base Obligation During Light Load Periods

4-3		Partial Requirements Resources

7-2		Calculation of the Monthly Demand Charges in the Duke-Blue Ridge Agreement, Duke-Piedmont Agreement and Duke-Rutherford Agreement

7-3		Calculation of Piedmont Allocated Share of Duke Total Hourly Energy Charge, EMC Group Total Hourly Energy Credit, Inter-EMC Energy Charge and Inter-EMC Energy Credit

7-4		Calculation of Blue Ridge, Piedmont and Rutherford Allocated Shares of the Duke Total Hourly Energy Charge, EMC Group Total Hourly Energy Credit, Inter-EMC Energy Charge and Inter-EMC Energy Credit

7-5		Example showing Calculations of Piedmont Energy Purchase Amounts and Piedmont Energy Credit Amount


7-6		Example showing Calculations of EMC Group Energy Purchase Amounts and EMC Group Energy Credit Amount

7-7		Example showing the calculation of Monthly Billing Demand under Section 7.2.6.3.2

7-8		Examples showing the calculation of Monthly Billing Demand under Section 7.3.2.2

7-9		Demand Rate Adjustment Percentage and Annual Percentage

7-10		Example of Demand Rate Adjustment Percentage and Annual Percentage

8-1 I		Terms and Conditions for the Scheduling of Power Supplied by North Carolina Electric Membership Corporation to its Independent Members

8-1 II		Terms and Conditions for Obtaining Transmission Services Adequate to Deliver from the Interface Points Established under the Wholesale Power Supply Agreement of NCEMC for Sales to its Independent Members

PARTIAL REQUIREMENTS SERVICE AGREEMENT

BETWEEN

DUKE POWER COMPANY LLC

d/b/a DUKE ENERGY CAROLINAS, LLC

AND

PIEDMONT ELECTRIC MEMBERSHIP CORPORATION

THIS PARTIAL REQUIREMENTS SERVICE AGREEMENT, dated as of May 12, 2006, is entered into by and between Piedmont Electric Membership Corporation, a corporation organized and existing under Article 2 of Chapter 117 of the General Statutes of North Carolina, together with any permitted successor or assignee (“EMC” or “Piedmont”), and Duke Power Company LLC, d/b/a Duke Energy Carolinas, LLC, a limited liability company organized and existing under the laws of North Carolina, together with any permitted successor or assignee (“Duke”). Hereinafter, Duke and EMC are sometimes also referred to individually as a “Party” or collectively as the “Parties.”

W I T N E S S E T H

WHEREAS, Duke is engaged in the business of generating, transmitting, and distributing electric capacity and energy in portions of the States of North Carolina and South Carolina, and provides electric service to retail and wholesale customers; and

WHEREAS, EMC is an electric membership corporation that provides retail electric service to its members in the State of North Carolina, and is authorized to purchase electric energy at wholesale for resale; and

WHEREAS, EMC is a member of North Carolina Electric Membership Corporation (“NCEMC”) and is a party to the WPSA; and

WHEREAS, EMC is a party to the PPA; and

WHEREAS, EMC has elected to arrange independently from NCEMC for its future requirements for electric capacity and energy in addition to those to which EMC has entitlements under existing contractual arrangements; and

WHEREAS, EMC has reviewed its future needs for electric capacity and energy and Scheduling Agent Services and has determined that in order for EMC to provide for a portion of EMC’s Native Load, EMC is willing to purchase electric capacity and energy from Duke and is also willing to purchase Scheduling Agent Services from Duke for the duration of, and subject to the terms of, this Agreement; and

WHEREAS, Duke is willing to plan and provide for the electric capacity and energy requirements needed to meet a portion of EMC’s Native Load and to provide Scheduling Agent Services for the duration of, and subject to the terms of, this Agreement; and

WHEREAS, Duke and EMC have agreed to the terms and conditions upon which the sale of electric capacity and energy and provision of Scheduling Agent Services may be conducted between the Parties.

NOW THEREFORE, in consideration of the premises and the mutual representations, warranties and covenants set forth in this Agreement, and for other good and valuable consideration, the receipt and adequacy of which is hereby acknowledged, the Parties, each intending to be legally bound, hereby agree as follows:

Article 1

Definitions

1.1	Definitions .

Defined terms in this Agreement are capitalized. The defined terms used in this Agreement have the following meanings:

“Accounting Requirements” shall have the meaning specified in Section 15.7.

“Administrator” shall mean the RUS Administrator.

“Adverse Ruling” shall have the meaning specified in Section 3.1(c).

“Affiliate” means, with respect to any person, any other person directly or indirectly controlling or controlled by, or under direct or indirect common control with, such person. For purposes of this definition, “control” when used with respect to any person means the power to direct the management and policies of such person, directly or indirectly, whether through the ownership of voting securities, by contract or otherwise, and the terms “controlling” and “controlled” have meanings correlative to the foregoing.

“Agreement” means this Partial Requirements Service Agreement, together with each Schedule and Attachment, each as amended from time to time.

“Ancillary Services” means any and all ancillary services provided by the Transmission Provider in connection with any Transmission Service arranged by EMC for the delivery of electric energy provided under this Agreement from the Delivery Point.

“Annual Capacity Factor” shall have the meaning specified in Section 4.3.3.1.

“Annual Capacity Price” shall have the meaning specified in Section 3.5.2.3.1, 3.5.2.3.2, 3.5.2.3.3 or 7.2.2, as applicable.

“Annual Capacity Quantity” shall have the meaning specified in Sections 3.5.2.3.1, 3.5.2.3.2, 3.5.2.3.3 or 7.2.2, as applicable.

“Annual Percentage” shall be calculated as shown on Attachment 7-9 .

“Annual Planning Period” means, the period (as of the Commencement Date either May through September or October through April) designated in the then most recent Duke Annual Plan (or the successor thereto) that Duke files with the NCUC as the period during which Duke’s annual peak load is projected to occur; provided, that in the event that NCUC ceases to require Duke to file or filing becomes voluntary and Duke ceases to file the Duke Annual Plan (or a successor thereto) with the NCUC, “Annual Planning Period” shall mean the period (either May through September or October through April) in which Duke’s annual peak load is projected to occur under the generation planning criteria for Duke’s Generation System used by Duke to meet Duke’s Native Load.

“Assignment for Security” shall have the meaning specified in Section 16.2.2.

“Bankrupt” means that the Defaulting Party or any guarantor of such Party:

(i) is dissolved (other than pursuant to a consolidation, amalgamation or merger);

(ii) becomes insolvent or is unable to pay its debts or fails or admits in writing its inability generally to pay its debts as they become due;

(iii) makes a general assignment, arrangement or composition with or for the benefit of its creditors;

(iv) institutes or has instituted against it a proceeding seeking a judgment of insolvency or bankruptcy or any other relief under any bankruptcy or insolvency law or other similar law affecting creditor’s rights, or a petition is presented for its winding-up or liquidation;

(v) has a resolution passed for its winding-up, official management or liquidation (other than pursuant to a consolidation, amalgamation or merger);

(vi) seeks or becomes subject to the appointment of an administrator, provisional liquidator, conservator, receiver, trustee, custodian or other similar official for it or substantially all of its assets;

(vii) has a secured party take possession of all or substantially all of its assets, or has a distress, execution, attachment, sequestration or other legal process levied, enforced or sued on or against all or substantially all of its assets;

(viii) causes or is subject to any event with respect to it which, under the applicable Laws of any jurisdiction, has an analogous effect to any of the events specified in clauses (i) to (vii) inclusive; or

(ix) takes any action in furtherance of, or indicating its consent to, approval of, or acquiescence in, any of the foregoing acts.

“Bankruptcy Code” means Title 11 of the United States Code or any successor thereto.

“Base Annual Capacity Charge” means the charge set forth in Section 3.5.2.3.4 or 7.2.2, as applicable.

“Baseload Resources” means the Partial Requirements Resources identified as Baseload Resources in Attachment 4-3 .

“Billing Dispute Notice” shall have the meaning specified in Section 13.5.

“Billing Period” means the period beginning on the Commencement Date and ending on the last Day of the Month in which the Commencement Date occurred, and each succeeding Month thereafter.

“Blue Ridge” means Blue Ridge Electric Membership Corporation.

“Blue Ridge Energy Credit Amount” means the Blue Ridge Energy Credit Amount as determined in Section 7.1.5.9 of the Duke-Blue Ridge Agreement.

“Blue Ridge Energy Purchase Amount” means the Blue Ridge Energy Purchase Amount as determined in Section 7.1.5.9 of the Duke-Blue Ridge Agreement.

“Business Day” means any Day other than Saturday, Sunday, or any Day on which the Federal Reserve member banks are not open for business.

“Catawba Nuclear Station” means that certain nuclear power plant located near Rock Hill in York County, South Carolina.

“CFC” shall have the meaning specified in Section 15.7.

“Claiming Party” shall have the meaning specified in Section 16.4.

“Claims” means all third party claims or actions, threatened or filed, and whether groundless, false, or fraudulent, that directly or indirectly relate to the subject matter of an indemnity, and the resulting losses, damages, expenses, attorneys’ fees, and court costs, whether incurred by settlement or otherwise, and whether such claims or actions are threatened or filed prior to or after the termination of this Agreement.

“CoBank” shall have the meaning specified in Section 15.7.

“Combined Cycle Resources” means the Partial Requirements Resources identified as Combined Cycle Resources in Attachment 4-3 .

“Commencement Date” shall have the meaning specified in Section 2.1.1.

“Commercially Reasonable Efforts” means efforts which are reasonably within the contemplation of the Parties at the Effective Date; which require the performing Party that is acting in good faith to take action or expend funds reasonably in relation to the benefit to be obtained by the other Party; and that require a level of effort which would be devoted by an independent entity reasonably in the electric utility industry in light of all of the relevant circumstances.

“Confidential Information” means any documents, analyses, compilations, studies, or other materials prepared by a Party or its Representatives that contain or reflect either (a) any costs of Duke’s Generation System, including system average costs, System Incremental Costs, Territorial Incremental Costs, and Territorial Decremental Costs, or (b) written or oral data or information that is privileged, confidential, or proprietary and is marked as “Confidential.” “Confidential Information” shall also mean all subsequently prepared documents, analyses, compilations, studies, or other materials by a Party or its Representative that are derived from previously marked “Confidential” data or information. Notwithstanding the foregoing, information shall not be deemed Confidential Information if it:

(i) is a matter of public knowledge at the time of its disclosure or is thereafter published in or otherwise ascertainable from any source available to the public without breach of this Agreement,

(ii) constitutes information which is obtained from a third party (who or which is not an Affiliate of one of the Parties) other than by or as a result of unauthorized disclosure, or

(iii) prior to the time of disclosure had been independently developed by the receiving Party or its Affiliates not utilizing improper means.

“Control Area” means an electric power system or combination of electric power systems to which a common automatic generation control scheme is applied in order to match the power output of the generators within the electric power system and electric energy imported into the electric power system, with the load located within the electric power system.

“Cover Costs” shall have the meaning specified in Section 6.4.

“CP&L” means Carolina Power & Light Company (d/b/a Progress Energy Carolinas, Inc.).

“CPR” shall have the meaning specified in Section 14.1.

“Day” means a day, commencing at 00:00:00 Eastern Time of such calendar day and ending 23:59:59 Eastern Time of the same calendar day.

“Debt Service Coverage Ratio” shall have the meaning specified in Section 15.7.

“Defaulting Party” shall have the meaning specified in Section 16.5.1.

“Delivery Points” means any available points on the Transmission System where electric energy is delivered for Transmission Service.

“Demand Rate Adjustment Percentage” shall be calculated as shown on Attachment 7-9 .

“Demand Side Management Resource Programs” means the demand side management resource programs that Duke makes available to Duke’s Native Load retail customers within the State of North Carolina under riders approved and on file with the NCUC, as such riders may be amended from time to time.

“Depreciation and Amortization Expense” shall have the meaning specified in Section 15.7.

“Dispatched Baseload Resources” means the Baseload Resources that Duke dispatches pursuant to Section 4.3.4.

“Dispatched Combined Cycle Resources” means the Combined Cycle Resources that Duke dispatches pursuant to Section 4.3.3.

“Disputed Amount” shall have the meaning specified in Section 13.5.

“Duke” shall have the meaning specified in the first paragraph hereof, provided that for purposes of this Agreement “Duke” shall not include Duke Transmission and provided further, Duke intends to effectuate a name change to Duke Energy Carolinas, LLC and upon the effectiveness of such name change, references to “Duke” shall mean Duke Energy Carolinas, LLC.

“Duke Annual Plan” means the Annual Report Duke is required to file with the NCUC in accordance with NCUC Rule R8-60 or successor thereto. In the event Duke is no longer required to file the Annual Report with the NCUC or filing becomes voluntary, “Duke Annual Plan” shall mean the generation planning criteria for Duke’s Generation System used by Duke to meet Duke’s Native Load.

“Duke-Blue Ridge Agreement” means the Partial Requirements Service Agreement between Duke and Blue Ridge Electric Membership Corporation, dated May 12, 2006.

“Duke Hourly Energy Charge” shall have the meaning specified in Section 7.1.5.1 or 7.2.5.2, as applicable.

“Duke Hourly Reconciliation Charge” shall have the meaning specified in Section 7.1.5.11.

“Duke Monthly Energy Charge” means, with respect to the period beginning on the Commencement Date and continuing through December 31, 2006, the charge set forth in Section 7.1.5.1; with respect to the period January 1, 2007, through December 31, 2010, the charge set forth in Section 7.2.5.1 or 7.2.6.4, as applicable; and with respect to the period beginning January 1, 2011, and continuing through the termination of this Agreement, the charge set forth in Section 7.3.3.

“Duke Monthly Reconciliation Charge” shall have the meaning specified in Section 7.1.5.11.

“Duke Native Load” or “Duke’s Native Load” means the electric capacity and energy demands imposed on Duke by its retail customers located within Duke’s Service Area, as such Service Area may be amended from time to time in accordance with Laws or pursuant to the requisite approvals of the Governmental Authorities that have jurisdiction to regulate retail electric service within such Service Area, including by merger or acquisition, plus the demands of Duke’s wholesale power sales customers served under contracts with a firmness of supply equal to such retail customers.

“Duke-Piedmont Agreement” means this Agreement.

“Duke-Rutherford Agreement” means the Partial Requirements Service Agreement between Duke and Rutherford Electric Membership Corporation, dated as of May 12, 2006.

“Duke Reconciliation Amount” shall have the meaning specified in Section 7.1.5.11.

“Duke’s Generation Planning Practices” means the then-current generation planning practices of Duke that are reflected in the Duke Annual Plan.

“Duke’s Generation System” means Duke’s owned or leased electric generating facilities and purchased power resources the output of which are used to serve Duke’s Native Load located within the State of North Carolina, as such system may be amended from time to time by any means including by merger or acquisition.

“Duke Schedule 1 Demands” shall have the meaning specified in Schedule 1, Section I.B.

“Duke Total Hourly Energy Charge” shall have the meaning specified in Section 7.1.5.2.

“Duke Transmission” means Duke Electric Transmission, a division of Duke, or any successor thereto.

“Eastern Time” means the time in effect in Charlotte, North Carolina, whether Eastern Standard Time or Eastern Daylight Saving Time.

“Effective Date” shall have the meaning specified in Section 2.1.1.

“EMC” or “Piedmont” shall have the meaning specified in the first paragraph of this Agreement.

“EMC Call Signal”, with respect to the period beginning on the Commencement Date and continuing through December 31, 2006, shall have the meaning specified in Section 7.1.5.9; and with respect to the period beginning January 1, 2007, through December 31, 2010, shall have the meaning specified in Section 7.2.5.5.

“EMC Coincident Peak Demand” shall have the meaning specified in Section 3.5.2.3.5.1 or 7.2.3.2, as applicable.

“EMC Contract Resources”, with respect to the period beginning on the Commencement Date and continuing through December 31, 2010, shall have the meaning specified in Section 5.1.1, and with respect to the period beginning January 1, 2011, and continuing through the termination of this Agreement, shall have the meaning specified in Section 5.2.1.

“EMC Demand Side Management Resource Programs” means the demand side management resource programs that EMC makes available to EMC’s Native Load customers.

“EMC Excess Annual Capacity Quantity” shall have the meaning specified in Section 3.5.2.3.5.1 or 7.2.3.2, as applicable.

“EMC Group” means collectively Piedmont, Blue Ridge, and Rutherford.

“EMC Group Annual Capacity Quantity” means the sum of: (i) the Annual Capacity Quantity set forth in Section 3.5.2.3 of this Agreement; (ii) the Annual Capacity Quantity set forth in Section 3.5.2.3 of the Duke-Blue Ridge Agreement; and (iii) the Annual Capacity Quantity set forth in Section 3.5.2.3 of the Duke-Rutherford Agreement.

“EMC Group Call Signal” shall have the meaning specified in Section 7.1.5.10.

“EMC Group Coincident Peak Demand” shall have the meaning specified in Section 3.5.2.3.5.3.

“EMC Group Combined Energy Credit Amount” means the sum of (i) the Blue Ridge Energy Credit Amount, (ii) the Piedmont Energy Credit Amount, and (iii) the Rutherford Energy Credit Amount.

“EMC Group Combined Energy Purchase Amount” means the sum of (i) the Blue Ridge Energy Purchase Amount, (ii) the Piedmont Energy Purchase Amount, and (iii) the Rutherford Energy Purchase Amount.

“EMC Group Combined Excess Annual Capacity Quantity” shall have the meaning specified in Section 3.5.2.3.5.2.

“EMC Group Combined Monthly Demand Quantity” shall have the meaning specified in Section 7.1.4.2.

“EMC Group Energy Credit Amount” shall have the meaning specified in Section 7.1.5.10.

“EMC Group Energy Purchase Amount” shall have the meaning specified in Section 7.1.5.10.

“EMC Group Excess Annual Capacity Quantity” shall have the meaning specified in Section 3.5.2.3.5.3.

“EMC Group Monthly Demand Quantity” shall have the meaning specified in Section 7.1.4.3.

“EMC Group Native Load” means the sum of (i) the EMC Native Load under this Agreement, (ii) the EMC Native Load under the Duke-Blue Ridge Agreement, and (iii) the EMC Native Load under the Duke-Rutherford Agreement.

“EMC Group Put Signal” shall have the meaning specified in Section 7.1.5.10.

“EMC Group Reconciliation Amount” shall have the meaning specified in Section 7.1.5.12.

“EMC Group Total Hourly Energy Credit” shall have the meaning specified in Section 7.1.5.6.

“EMC Group’s Base Obligation” means the sum of (i) EMC’s Base Obligation under Section 4.2.2 of this Agreement, (ii) EMC’s Base Obligation under Section 4.2.2 of the Duke-Blue Ridge Agreement, and (iii) EMC’s Base Obligation under Section 4.2.2 of the Duke-Rutherford Agreement.

“EMC Hourly Demand” shall have the meaning specified in Section 3.5.2.3.5.1 or 7.2.3.2, as applicable.

“EMC Hourly Energy Credit”, with respect to the period beginning on the Commencement Date and continuing through December 31, 2006, shall have the meaning specified in Section 7.1.5.5; and with respect to the period beginning January 1, 2007, through December 31, 2010, shall have the meaning specified in Section 7.2.5.4.

“EMC Monthly Demand Quantity”, with respect to the period beginning on the Commencement Date and continuing through December 31, 2006, shall have the meaning specified in Section 7.1.4.1; and with respect to the period beginning January 1, 2007, through December 31, 2010, shall have the meaning specified in Section 7.2.4.1.

“EMC Monthly Energy Credit”, with respect to the period beginning on the Commencement Date and continuing through December 31, 2006, shall mean the credit set forth in Section 7.1.5.5; and with respect to the period beginning January 1, 2007, through December 31, 2010, shall mean the credit set forth in Section 7.2.5.3.

“EMC Peak Hour Billing Demand”, with respect to the period January 1, 2007 through December 31, 2010, shall have the meaning specified in Section 7.2.6.3.2, and with respect to the period beginning January 1, 2011, and continuing through the termination of this Agreement, shall have the meaning specified in Section 7.3.2.2.

“EMC Put Signal”, with respect to the period beginning on the Commencement Date and continuing through December 31, 2006, shall have the meaning specified in Section 7.1.5.9; and with respect to the period beginning January 1, 2007, through December 31, 2010, shall have the meaning specified in Section 7.2.5.5.

“EMC Scheduled Amount” shall have the meaning specified in Section 4.2.3.

“EMC’s Base Obligation” shall have the meaning specified in Section 4.2.2.

“Energy Cost” shall have the meaning specified in Section 4.3.3.3.

“Energy Imbalance Service” means the service provided under Schedule 4 of the Transmission Provider’s OATT.

“Equitable Defenses” means, with respect to a proceeding involving this Agreement, the discretion of a Governmental Authority to make or enter an order of bankruptcy, insolvency, reorganization, or other ruling affecting creditors’ rights generally, or exercising other discretion committed to the court’s or agency’s equitable powers.

“Equity” shall have the meaning specified in Section 15.7.

“Event of Default” shall have the meaning specified in Section 16.5.1.

“Excepted Load” shall have the meaning specified in Section 4.4.

“Excess Annual Amount” means the quantity specified in Section 3.5.2.3.5.

“Excess Annual Capacity Charge” means the charge specified in Section 3.5.2.3.5 or 7.2.3, as applicable.

“Excess Annual Capacity Price” shall have the meaning specified in Section 3.5.2.3.1, 3.5.2.3.2, 3.5.2.3.3 or 7.2.3.1, as applicable.

“Extension Term” shall have the meaning specified in Section 2.2.2.

“Federal Power Act” means the Federal Power Act, 16 U.S.C. §§791a-828c, as amended from time to time.

“FERC” means the Federal Energy Regulatory Commission or any successor agency that administers the Federal Power Act.

“FFR Supplemental Service” shall have the meaning specified in Sections 4.1 and 4.2.

might have the right to determine the standards for character of service and firmness of supply, including standards that may require the designation of specific capacity sources, under which EMC may designate the PPA, such that the requirements of the highest firm transmission priority are met under its Network Integration Transmission Service Agreement (or as the nearest equivalent thereto remains available to EMC under the successor Transmission Provider’s requirements).

“Firm Sales” means wholesale electric sales other than Non-Firm Sales.

“Fitch Rating” means Fitch, Inc., a unit of Fimalac, S.A.

“Fixed Forward Resource” or “FFR Resource” means EMC’s contractual entitlements to electric capacity and energy under the PPA.

“Force Majeure” shall have the meaning specified in Section 16.4.

“Fuel Rate”, with respect to the period January 1, 2007, through December 31, 2010, shall have the meaning specified in Section 7.2.6.4.1, and with respect to the period beginning January 1, 2011, and continuing through the termination of this Agreement, shall have the meaning specified in Section 7.3.3.1.

“Government” means the United States government.

“Governmental Authority” means any federal, state, local or other governmental, regulatory or administrative agency, court, commission, department, board, or other governmental subdivision, legislature, rulemaking board, court, tribunal, arbitrating body, government-owned corporation or other governmental authority or department thereof.

“Governmental Charges” means all taxes, fees, assessments and other charges imposed by any Governmental Authority.

“Hour” means one of the twenty-four (24) clock hours in a Day.

“Hourly Fuel Charge”, with respect to the period January 1, 2007, through December 31, 2010, shall have the meaning specified in Section 7.2.6.4.1, and with respect to the period beginning January 1, 2011, and ending on the termination of this Agreement, shall have the meaning specified in Section 7.3.3.1.

“Hourly Inter-EMC Transfer Reconciliation Charge” shall have the meaning specified in Section 7.1.5.13.

“Hourly Variable O&M Charge”, with respect to the period January 1, 2007, through December 31, 2010, shall have the meaning specified in Section 7.2.6.4.2, and with respect to the period beginning January 1, 2011, and ending on the termination of this Agreement, shall have the meaning specified in Section 7.3.3.2.

“Initial Term” shall have the meaning specified in Section 2.2.1.

“Impasse Notice” shall have the meaning specified in Section 14.2.

“Interest Expense” shall have the meaning specified in Section 15.7.

“Interest Rate” means either (i) the Prime Rate plus two (2%) percent, or (ii) the maximum lawful rate permitted by applicable Law, whichever is less.

“Interval”, with respect to the period beginning on the Commencement Date and continuing through December 31, 2006, shall have the meaning specified in Section 7.1.5.9 and 7.1.5.10, as applicable; and with respect to the period beginning January 1, 2007, through December 31, 2010, shall have the meaning specified in Section 7.2.5.5.

“ITC” means an independent transmission company.

“ISO” means an independent system operator.

“kWh” means kilowatt-hour, a unit of electric energy.

“kW” means kilowatt.

“Law” means any law, rule, regulation, order, writ, judgment, decree, or other legal or regulatory determination by a court, regulatory agency, or other Governmental Authority of competent jurisdiction.

“Legal Proceeding” means any suit, hearing, or proceeding by or before any court or any Governmental Authority.

“Light Load Periods” means any Hour during which EMC’s Base Obligation is reduced because certain of its entitlements to electric capacity and energy under the WPSA are reduced as a result of NCEMC’s Native Load in either of the CP&L east or west Control Areas or Duke Control Area being insufficient to permit NCEMC to have access to its full contractual entitlement to electric capacity and energy from certain generation or purchased power resources.

(i) For each Hour beginning with the Commencement Date and continuing through December 31, 2010, or any portion thereof in which this Agreement is in effect, Light Load Periods in the CP&L east and west Control Areas, only occur when NCEMC’s Native Load in such CP&L east and west Control Area is less than the contractual amount specified in the Service Obligation Resources (“SORs”). The amount of any reduction in NCEMC’s entitlement to electric capacity and energy under the SORs is allocated to EMC in accordance with the WPSA. In the Duke Control Area, Light Load Periods only occur when a generating unit at either the Catawba Nuclear Station or the McGuire Nuclear Station is off-line or de-rated and NCEMC’s Native Load in the Duke Control Area is less than 623.5 MWs. The amount of any reduction in NCEMC’s entitlement to electric capacity and energy is allocated to EMC in accordance with the WPSA.

(ii) For each Hour beginning January 1, 2011, and continuing through the termination of this Agreement, Light Load Periods only occur when a generating unit at either the Catawba Nuclear Station or the McGuire Nuclear Station is off-line or de-rated and NCEMC’s Native Load in the Duke Control Area is less than 623.5 MWs. The amount of any reduction in NCEMC’s entitlement to electric capacity and energy is allocated to EMC in accordance with the WPSA.

“Material Adverse Change” or “MAC” shall have the meaning specified in Section 15.2.

“Material Adverse Ruling” shall have the meaning specified in Section 2.3.2.2(c).

“Material Adverse Ruling Termination Date” shall have the meaning specified in Section 2.3.2.2.

“Maximum Demand Hour”, with respect to the period beginning on the Commencement Date and continuing through December 31, 2006, shall have the meaning specified in Section 7.1.4.3; and with respect to the period January 1, 2007 through December 31, 2010, shall have the meaning specified in Section 7.2.4.1.

“McGuire Nuclear Station” means that certain nuclear plant located in Huntersville, North Carolina.

“Month” means a calendar month, commencing at one (1) minute prior to 12:01 a.m. Eastern Time on one of January 1, February 1, March 1, April 1, May 1, June 1, July 1, August 1, September 1, October 1, November 1 or December 1 and ending at one (1) minute after 11:59 p.m. Eastern Time of the succeeding January 31, February 28 or 29 (during a leap year), March 31, April 30, May 31, June 30, July 31, August 31, September 30, October 31, November 30 or December 31.

“Monthly” shall have a meaning correlative to that of Month.

“Monthly Billing Demand”, with respect to the period January 1, 2007, through December 31, 2010, shall have the meaning specified in Section 7.2.6.3.2, and with respect to the period beginning January 1, 2011, and continuing through the termination of this Agreement, shall have the meaning specified in Section 7.3.2.2.

“Monthly Demand Amount” means the quantity specified in Section 7.1.4.

“Monthly Demand Charge” means, with respect to the period beginning on the Commencement Date and continuing through December 31, 2006, the charge set forth in Section 7.1.4; with respect to the period January 1, 2007, through December 31, 2010, the charge set forth in Section 7.2.4 or 7.2.6.3, as applicable; and with respect to the period beginning January 1, 2011, and continuing through the termination of this Agreement, the charge set forth in Section 7.3.2.

meaning specified in Section 7.2.4 or 7.2.6.3.1, as applicable, except as provided in Sections 3.5.2.3.1, 3.5.2.3.2 and 3.5.2.3.3; with respect to the period September 1, 2008, through December 31, 2010, shall have the meaning specified in Section 7.2.4 or 7.2.6.3.1, as applicable, and with respect to the period beginning January 1, 2011, and continuing through the termination of this Agreement, shall have the meaning specified in Section 7.3.2.1.

“Monthly Fuel Charge”, with respect to the period January 1, 2007, through December 31, 2010, shall have the meaning specified in Section 7.2.6.4.1, and with respect to the period beginning January 1, 2011, and continuing through the termination of this Agreement, shall have the meaning specified in Section 7.3.3.1.

“Monthly Inter-EMC Energy Transfer Reconciliation Charge” shall have the meaning specified in Section 7.1.5.13.

“Monthly Replacement Energy Charge” shall have the meaning specified in Section 4.2.4.

“Monthly Reserve Capacity Charge” shall have the meaning specified in Section 7.4.

“Monthly Scheduling Agent Service Charge” shall have the meaning specified in Section 7.1.6.

“Monthly Variable O&M Charge”, with respect to the period January 1, 2007, through December 31, 2010, shall have the meaning specified in Section 7.2.6.4.2, and with respect to the period beginning January 1, 2011, and ending on the termination of this Agreement, shall have the meaning specified in Section 7.3.3.2.

“Moody’s” means Moody’s Investors Services, Inc.

“MSCG” means Morgan Stanley Capital Group Inc.

“MWh” means megawatt-hour, a unit of electric energy.

“MW” means megawatt.

“NCEMC” shall have the meaning specified in the Recitals of this Agreement.

“NCEMC Native Load” means the electric and energy demands imposed on NCEMC by its members for resale to such members’ retail customers, and shall include wholesale sales of electric capacity and energy by Blue Ridge to New River except wholesale sales of electric capacity and energy made in accordance with Section 4.4.1 of the Duke-Blue Ridge Agreement.

“NCEMC Policies” shall have the meaning specified in Section 8.2.

“NCUC” means the North Carolina Utilities Commission or any successor agency with jurisdiction to regulate retail electric service in the State of North Carolina.

“Negotiation Period” shall have the meaning specified in Section 14.2.

“NERC” means the North American Electric Reliability Council.

“Network Integration Transmission Service” means Network Integration Transmission Service provided under the OATT.

“Network Integration Transmission Service Agreement” or “NITSA” means that certain agreement for Network Integration Transmission Service, as amended from time to time, executed by EMC and Transmission Provider.

“Network Operating Agreement” or “NOA” means that certain agreement, as amended from time to time, executed by EMC and Transmission Provider in conjunction with the Network Integration Transmission Service Agreement.

“Network Resource” shall have the meaning specified in the OATT.

“Neutral Auditors” shall have the meaning specified in Section 2.3.2.2.2.

“New River” means Appalachian State University d/b/a New River Light & Power Company or any successor thereto.

“Nomination” means the notification provided by MSCG to the Scheduling Agent of the sources and specific amounts of electric energy under the WPSA that MSCG desires EMC to make available in accordance with the terms and conditions of the PPA.

“Non-Claiming Party” shall have the meaning specified in Section 16.4.

“Non-Conforming Load” shall have the meaning specified in Section 4.4.

“Non-Defaulting Party” shall have the meaning specified in Section 16.5.1.

“Non-Duke Control Area Load” means load that is located in a Control Area other than the Duke Control Area, including load that is physically located in the Duke Control Area but telemetered for Control Area purposes to another Control Area.

“Non-Firm Sales” means wholesale electric sales for which the delivery of electric energy may be interrupted, curtailed or terminated for any reason without any liability to Duke (other than charges imposed for changes to schedules for the sale of electric energy).

“Notice of Termination” means a written notice to terminate this Agreement under Sections 2.2 or 2.3 that conforms to the requirements set forth in Section 2.3.3.

“OATT” means the Open Access Transmission Tariff of the Transmission Provider on file with FERC, or the successor transmission tariff (including the Open Access Transmission Tariff of an RTO, ITC or ISO that is applicable to the Transmission System), as either may be amended from time to time.

“Operating Committee” shall have the meaning specified in Section 10.1.

“Option Notice” shall have the meaning specified in Section 3.5.2.3.

“Option Period” shall have the meaning specified in Section 3.5.2.3.

“Original Notice” shall have the meaning specified in Section 14.2.

“Partial Requirements Agreements” means the Duke-Rutherford Agreement, the Duke-Blue Ridge Agreement, and the Duke-Piedmont Agreement.

“Partial Requirements Resources” means EMC’s contractual entitlements to electric capacity and energy used to serve EMC’s Native Load during the period commencing January 1, 2011, and continuing through the termination of this Agreement, as specified in Section 5.2.

“Partial Requirements Service” shall have the meaning specified in Section 4.3.

“Party” and “Parties” shall have the meanings specified in the preamble of this Agreement.

“Patronage Capital or Margins” shall have the meaning specified in Section 15.7.

“Piedmont” shall have the meaning specified in the first paragraph of this Agreement.

“Piedmont Allocated Share of Duke Total Hourly Energy Charge” shall be as calculated in Attachment 7-3 .

“Piedmont Allocated Share of EMC Group Total Hourly Energy Credit” shall be as calculated in Attachment 7-3 .

“Piedmont Allocated Share of Inter-EMC Energy Charge” shall be as calculated in Attachment 7-3 .

“Piedmont Allocated Share of Inter-EMC Energy Credit” shall be as calculated in Attachment 7-3 .

“Piedmont Energy Credit Amount”, with respect to the period beginning on the Commencement Date and continuing through December 31, 2006, shall have the meaning specified in Section 7.1.5.9; and with respect to the period beginning January 1, 2007, through December 31, 2010, shall have the meaning specified in Section 7.2.5.5.

“Piedmont Energy Purchase Amount”, with respect to the period beginning on the Commencement Date and continuing through December 31, 2006, shall have the meaning specified in Section 7.1.5.9; and with respect to the period beginning January 1, 2007, through December 31, 2010, shall have the meaning specified in Section 7.2.5.5.

“Piedmont Hourly Reconciliation Credit” shall have the meaning specified in Section 7.1.5.12.

“Piedmont Monthly Reconciliation Credit” shall have the meaning specified in Section 7.1.5.12.

“Point of Interconnection” means the point of interconnection between the Transmission Provider’s transmission and distribution facilities and EMC’s system.

“PPA” means that certain Power Purchase Agreement by and between EMC and Morgan Stanley Capital Group Inc. dated as of December 11, 2003, as amended from time to time.

“Prime Rate” means, for any date, the per annum rate of interest announced from time to time by Citibank, N.A. (or a suitable replacement agreed upon by the Parties) as its “prime” rate for commercial loans, effective on the date payment is due as established from time to time by such bank.

“Principal and Interest Expense” shall have the meaning specified in Section 15.7.

“Prudent Utility Practice” means any of the practices, methods, and acts engaged in or approved by a significant portion of the electric utility industry during the relevant time period, or any of the practices, methods, and acts which, in the exercise of reasonable judgment in light of the facts known at the time the decision was made, could have been expected to accomplish the desired result at a reasonable cost consistent with good business practices, reliability, safety, and expedition. Prudent Utility Practice is not intended to be limited to the optimum practice, method, or act to the exclusion of all others, but rather to be acceptable practices, methods, or acts generally accepted in the electric utility industry.

“PSCSC” means the Public Service Commission of South Carolina, or any successor agency with jurisdiction to regulate retail electric service within the State of South Carolina.

“Purchasing - Selling Entity” means that entity designated to the Transmission Provider by EMC who, upon the effectiveness of such designation, is eligible to purchase and sell energy and/or capacity and reserve transmission services on behalf of EMC.

“PURPA” means the Public Utilities Regulatory Policies Act, 16 U.S.C. §2601 et seq . (2005), as amended, including amendments included in the Energy Policy Act of 2005.

“PURPA Resource” shall have the meaning specified in Section 5.4.1.

“Qualifying Facility” means a facility that meets the standards under 18 C.F.R. Part 292, Subpart B, as amended from time to time.

“Reconciliation Allocation Factor” shall be equal to the Reconciliation Allocation Number divided by the sum of the Reconciliation Allocation Numbers as set forth in this Agreement and in the Duke-Blue Ridge Agreement, and Duke-Rutherford Agreement.

“Reconciliation Allocation Number” shall be equal to 17.55.

“Replacement Energy” shall have the meaning specified in Section 4.2.4.

“Representatives” means, with respect to a Party, such Party’s officers, directors, employees, advisors, and representatives and such Party’s Affiliates and their respective officers, directors, employees, advisors, and representatives.

“Resolution Period” shall have the meaning specified in Section 2.3.2.2.2.

“Restricted Rentals” shall have the meaning specified in Section 15.7.

“RTO” means a regional transmission organization as that term is defined by FERC.

“RUS” means the Rural Utilities Service of the United States Department of Agriculture or any agency succeeding to the functions of RUS.

“Rutherford” means Rutherford Electric Membership Corporation.

“Rutherford Energy Credit Amount” means the Rutherford Energy Credit Amount as determined in Section 7.1.5.9 of the Duke-Rutherford Agreement.

“Rutherford Energy Purchase Amount” means the Rutherford Energy Purchase Amount as determined in Section 7.1.5.9 of the Duke-Rutherford Agreement.

“Scheduling Agent” means Duke acting as agent on behalf of EMC to perform Scheduling Agent Services.

“Scheduling Agent Services” shall have the meaning specified in Article 8.

“Scheduling Services Agreement” means that certain Scheduling Services Agreement by and between EMC and MSCG dated as of December 11, 2003, as amended.

“Scheduling Shortfall” shall have the meaning specified in Section 4.2.4.

“Scheduling Shortfall Amount” shall have the meaning specified in Section 4.2.4.

“Selection Date” shall have the meaning specified in Section 14.5.

“SERC” means the Southeastern Reliability Council.

“Service Area” means the area within a state or states within which an electric utility provides retail electric service as determined under the applicable Laws of such state or states.

“Service Obligation Resources” or “SORs” means those generation and purchased capacity resources used by NCEMC to serve NCEMC’s members for resale to such members’ retail customers, as such resources are specified in the Power Sales Agreement Between Carolina Power & Light Company and North Carolina Electric Membership Corporation dated as of November 2, 1998, as amended.

“Short Term Interest Expense” shall have the meaning specified in Section 15.7.

“S&P” or “Standard & Poor’s” means Standard & Poor’s Rating Group, a division of McGraw Hill, Inc.

“Standard Arbitration Process” shall mean the arbitration process described in Section 14.6.1.

“Streamlined Arbitration Process” shall mean the arbitration process described in Section 14.6.2.

“Submission” or “Submissions” shall have the meaning specified in Section 14.6.1(5).

“Substitute Energy” shall have the meaning specified in Section 6.4.

“Substitute Energy Costs” shall have the meaning specified in Section 6.5.

“Summer Period” means the period (as of the Commencement Date May 1 – September 30) designated as the summer period in the then most recent Duke Annual Plan.

“System Average Pricing Option” shall have the meaning specified in Section 7.2.6.1.

“System Average Pricing Option Notice” shall have the meaning specified in Section 7.2.6.1.

“System Average Pricing Option Period” shall have the meaning specified in Section 7.2.6.1.

“System Incremental Cost” means the incremental expense, measured in dollars per megawatt hour ($/MWh), incurred by Duke to supply the next megawatt-hour (MWh) of electric energy, after serving Duke’s Native Load customers’ requirements, and all other opportunity sales, during any Hour in which electric energy is purchased by EMC. System Incremental Cost shall include the replacement cost of fuel, fuel handling expense, variable operating and maintenance expense, emissions allowance replacement costs and other environmental compliance costs, the cost of starting and operating any generating units (including costs incurred due to minimum runtimes or loading levels), and other appropriate electric energy-related costs, including electric energy purchases from others, interchange power costs, and allocations of unit commitment costs, if any, all as determined prior to the Hour.

“Term” means the term of this Agreement determined in accordance with Section 2.2.3.

“Termination Assistance Service” shall have the meaning specified in Section 8.10.

“Territorial Decremental Cost” means the decrease in Duke’s expenses, measured in dollars per megawatt hour ($/MWh), in supplying Duke’s Native Load customers’ requirements due to Duke’s purchase of electric energy supplied by EMC. Territorial Decremental Cost shall include the reduction in fuel expense, fuel handling expense, variable operating and maintenance expense, emissions allowance replacement costs and other environmental compliance costs, the cost of starting and operating any generating units (including costs incurred due to minimum runtimes or loading levels), and other appropriate energy-related costs, including electric energy purchases from others, interchange power costs, and allocations of unit commitment costs, if any, all as determined prior to the Hour.

electric energy is purchased by EMC. Territorial Incremental Cost shall include the replacement cost of fuel, fuel handling expense, variable operating and maintenance expense, emissions allowance replacement costs and other environmental compliance costs, the cost of starting and operating any generating units (including costs incurred due to minimum runtimes or loading levels), and other appropriate electric energy-related costs, including electric energy purchases from others, interchange power costs, and allocations of unit commitment costs, if any, all as determined prior to the Hour.

“Times Interest Earned Ratio” or “TIER” shall have the meaning specified in Section 15.7.

“Transmission Provider” means any entity transmitting electric energy provided by Duke under this Agreement to the EMC distribution system, and shall include any ISO, RTO, ITC, or other future organization, agency or authority that has been approved by FERC to serve as the Transmission Provider.

“Transmission Service” means the service provided by a Transmission Provider to EMC pursuant to which electric energy provided under this Agreement is delivered from the Delivery Point to EMC’s distribution system.

“Transmission System” means the electric transmission system owned or leased and operated by Duke Transmission.

“Variable O&M Rate”, with respect to the period January 1, 2007, through December 31, 2010, shall have the meaning specified in Section 7.2.6.4.2, and with respect to the period beginning January 1, 2011, and continuing through the termination of this Agreement, shall have the meaning specified in Section 7.3.3.2.

“Weekday” means Monday, Tuesday, Wednesday, Thursday or Friday, excluding days recognized as holidays by NERC.

“Weekend Day” means Saturday or Sunday, and all days recognized as holidays by NERC.

“Winter Period” means the period (as of the Commencement Date October 1 – April 30) designated as the winter period in the then most recent Duke Power Annual Plan.

“WPSA” means the Wholesale Power Supply Agreement by and between North Carolina Electric Membership Corporation and EMC dated as of January 1, 2004, as amended from time to time. The Parties agree that, for the purposes of this Agreement, the WPSA as in effect on the date hereof is attached to a letter from EMC to Duke dated May 12, 2006.

“Year” means a calendar year.

Agreement as a whole and not to any particular provision of this Agreement. Whenever the terms “include,” “includes,” or “including” are used herein in connection with a listing of items included within a prior reference, such listing shall be interpreted to be illustrative only, and shall not be interpreted as a limitation on or exclusive listing of the items included within the prior reference. Any reference in this Agreement to “Section,” “Article,” “Schedule,” or “Attachment” shall be references to this Agreement unless otherwise stated, and all such Sections, Articles, Schedules, and Attachments shall be incorporated in this Agreement by reference. In the event that any index or publication referenced in this Agreement ceases to be published, each such reference shall be deemed a reference to a successor or alternate index or publication reasonably agreed to by the Parties. Unless specified otherwise, a reference to a given agreement or instrument, and all schedules and attachments thereto, shall be a reference to that agreement or instrument as modified, amended, supplemented and restated, and in effect from time to time. Unless otherwise stated, any reference in this Agreement to any entity shall include its permitted successors and assignees, and in the case of any Governmental Authority, any person succeeding to its functions and capacities. All dollar amounts referred to in this Agreement shall be in U.S. currency.

1.3 Construction . The Parties acknowledge that each was actively involved in the negotiation and drafting of this Agreement and that no Law or rule of construction shall be raised or used in which the provisions of this Agreement shall be construed in favor of or against either Party because one is deemed to be the author thereof.

Article 2

Term

2.1	Effectiveness .

2.1.1 Effectiveness of this Agreement . This Agreement shall become effective upon execution and delivery by the Parties (“Effective Date”) provided that obligations of the Parties to purchase and sell electric capacity and energy and to provide Scheduling Agent Services shall commence, on the later to occur of (a) September 1, 2006 or (b) the date upon which service commences in accordance with Section 3.5.1.2 or Section 3.5.2.1 (the “Commencement Date”), provided that the Commencement Date shall be the first Day of the Month.

2.1.2 Governmental Approval .

2.1.2.1 Duke shall take appropriate steps within five (5) Business Days from the Effective Date to file this Agreement, together with supporting documents, with FERC pursuant to the requirements of the Federal Power Act. Thereafter, Duke shall diligently pursue acceptance of this Agreement as a rate schedule by FERC and shall keep EMC informed of the progress in such regard. If requested by Duke, EMC shall undertake Commercially Reasonable Efforts to cooperate with and assist Duke in Duke’s efforts to make this Agreement effective and, upon Duke’s request, shall make a timely submittal at FERC affirmatively supporting the acceptance or approval of this Agreement by FERC without modification, suspension, investigation, or other condition.

2.1.2.2 EMC shall take appropriate steps within five (5) Business Days from the Effective Date to submit this Agreement, together with supporting documents, to the RUS. Thereafter, EMC shall diligently pursue approval of this Agreement by the RUS and shall keep Duke informed of the progress in such regard. If requested by EMC, Duke shall undertake Commercially Reasonable Efforts to cooperate with and assist EMC in EMC’s efforts to obtain RUS approval of this Agreement and, upon EMC’s request, shall make a timely submittal at RUS affirmatively supporting the approval of this Agreement without modification or condition.

2.2

Term .

2.2.1 Initial Term . The initial term of this Agreement shall commence on the Effective Date and shall continue through 23:59:59, Eastern Time, on December 31, 2021 (“Initial Term”) unless this Agreement is terminated prior to December 31, 2021, in accordance with Sections 2.3.2, 3.5.2.2 or 3.5.3.

2.2.2 Extension . Unless terminated in accordance with Sections 2.3, 3.5.2.2 or 3.5.3, the Term of this Agreement shall automatically renew and extend for an additional term of ten (10) Years (each such extension being an “Extension Term”), so that unless either Party gives Notice of Termination in accordance with Section 2.3, the Term of this Agreement shall extend through 23:59:59 Eastern Time on December 31, 2031. Likewise, unless either Party gives Notice of Termination in accordance with Section 2.3, the Term of this Agreement shall extend through 23:59:59 Eastern Time on December 31, 2041; and so forth thereafter in ten (10) Year increments.

2.2.3 Term . The Initial Term of this Agreement together with each Extension Term, if any, shall constitute the “Term” of this Agreement during which Duke shall provide either FFR Supplemental Service or Partial Requirements Service, as applicable, and Scheduling Agent Services to EMC.

2.3	Termination .

2.3.1 Termination of the Initial or an Extension Term . Either Party may terminate this Agreement at the end of the Initial Term by giving Notice of Termination to the other Party as specified in Section 2.3.3 at least three (3) Years prior to the end of the Initial Term, so that such notice is given no later than December 31, 2018. If the Term is extended beyond the Initial Term pursuant to Section 2.2.2, either Party may terminate this Agreement at the end of the then-current Extension Term by providing Notice of Termination to the other Party as specified in Section 2.3.3 at least three (3) Years prior to the end of such Extension Term, so that such notice is given no later than December 31, 2028, for the Extension Term ending December 31, 2031, and so forth thereafter.

2.3.2 Early Termination . Notwithstanding the provisions of Section 2.3.1, early termination of this Agreement, including any Extension Term, shall only be permitted in the six (6) circumstances set out in Sections 2.3.2.1, 2.3.2.2, 2.3.2.3, 2.3.2.4, 2.3.2.5 and 2.3.2.6.

2.3.2.1 Early Termination for an Event of Default . In the event that an Event of Default occurs, and the Defaulting Party fails to cure such Event of Default within the time

period(s) specified in Section 16.5.3, the Non-Defaulting Party may terminate this Agreement upon giving thirty (30) Days’ Notice of Termination, provided that the termination date shall be the last Day of a Month.

2.3.2.2 Early Termination for a Material Adverse Ruling . In the event that a Material Adverse Ruling occurs, the Party affected by such Material Adverse Ruling may, within twenty (20) Days after such Material Adverse Ruling occurs, give the other Party Notice of Termination, in accordance with Section 2.3.3, of its intent to terminate this Agreement effective on 23:59:59 of the last Day of the Month that is twenty-four (24) Months after the Month in which the Notice of Termination is given. Such termination date shall be referred to herein as the “Material Adverse Ruling Termination Date.” If a Party fails to give Notice of Termination within twenty (20) Days after a Material Adverse Ruling occurs, it shall have permanently waived its right to terminate this Agreement due to such Material Adverse Ruling pursuant to this Section 2.3.2.2. Termination pursuant to this Section 2.3.2.2 shall be subject to the following procedures:

(a) During the ninety (90) Days immediately following the giving of the Notice of Termination, the Parties shall attempt to negotiate amendments to this Agreement that would permit the Parties to restore the equivalent value of the economic bargain contemplated by this Agreement absent the Material Adverse Ruling. If the Parties reach agreement, such amendments will not become effective unless, within one hundred eighty (180) Days of the date that the Notice of Termination is given, the Parties have obtained the necessary approvals of Governmental Authorities to enable the amendments to become effective without change, condition or modification. In the event that the Parties fail (i) to reach agreement on such amendments, or (ii) to obtain the necessary approvals of Governmental Authorities, this Agreement shall terminate on the Material Adverse Ruling Termination Date, subject to the provisions of Section 2.3.2.2(b) and 2.3.2.2.2.

(b) In the event that the Parties are unable to reach agreement on the amendments provided in Section 2.3.2.2(a), either Party may, no later than ninety (90) Days after the date that the Notice of Termination is given (or, if earlier, the date that the Parties mutually agree that they are unable to reach agreement on such amendments), give notice to the other Party of its desire to extend this Agreement for a period of up to twelve (12) Months beyond the Material Adverse Ruling Termination Date. Such extension will be subject to the Parties (i) having first reached agreement upon the rates, terms and conditions of service for such twelve (12) Month period within one hundred twenty (120) Days of the date that the Notice of Termination is given and executing such agreement within such one hundred twenty (120) Day period, and (ii) having received from Governmental Authorities the necessary approvals for such rates, terms and conditions without change, condition or modification within one hundred eighty (180) Days of the date that the Notice of Termination is given.

disallows costs related to this Agreement, including any disallowance of Duke’s costs related to investments in generating facilities or binding contracts to purchase electric capacity and energy to provide service to EMC under this Agreement, or (D) for retail ratemaking or regulatory accounting and reporting purposes, assigns, allocates or makes pro forma adjustments with respect to the revenues or costs related to this Agreement, and (ii) adversely affects the relative economic position of either Party in a material way. For purposes of this definition only,

(1) “material” for Duke means that the effect of the order or action by the Governmental Authority or change in Law is reasonably projected to decrease Duke’s net revenues under this Agreement, or, in the case of a disallowance, assignment, allocation, or pro forma adjustment of revenues or costs for retail ratemaking or regulatory accounting or reporting purposes, either (i) decrease Duke’s net costs or increase Duke’s net revenues assigned or allocated to Duke’s retail customer classes, or (ii) increase Duke’s net costs or decrease Duke’s net revenues assigned or allocated to Duke’s wholesale customer class, by an aggregate amount equal to five percent (5%) or more of the total revenues to be paid by EMC to Duke under this Agreement over the then-remaining Term;

(2) “material” for EMC means that the effect of the order or action by the Governmental Authority or change in Law is reasonably projected to increase EMC’s net costs under this Agreement by an amount equal to five percent (5%) or more of the total revenues to be paid by EMC to Duke under this Agreement over the then-remaining Term;

(3) an increase in a Party’s net costs is the increase in the Party’s costs as a result of the order or action by the Governmental Authority or change in Law, less the increase (if any) in the Party’s revenues as a result of the Material Adverse Ruling; and

(4) a decrease in a Party’s net revenues is the decrease in the Party’s revenues as a result of the order or action by the Governmental Authority or change in Law, less the decrease (if any) in the Party’s costs as a result of the Material Adverse Ruling.

(d) The foregoing amounts shall be calculated on a nominal rather than an inflation adjusted or present value basis. Without limitation of the foregoing, EMC acknowledges that, for retail ratemaking and regulatory accounting and reporting purposes, Duke shall calculate the costs of the electric capacity and energy used to serve EMC under this Agreement on a system average cost basis beginning January 1, 2011, or upon the commencement of the System Average Pricing Option Period, if earlier. EMC agrees that if the amount of costs that the NCUC or the PSCSC in effect assigns or allocates to, or requires Duke to assign or allocate to, this Agreement for ratemaking or regulatory accounting and reporting purposes exceeds Duke’s system average costs, such action shall constitute a Material Adverse Ruling if the five percent (5%) materiality standard set forth above is met.

2.3.2.2.1 A change in Duke’s net revenues or EMC’s net costs that results from a change in this Agreement that is permitted under Section 12.3, shall not constitute a Material Adverse Ruling regardless of the impact of such change on either Party’s net costs or net revenues.

2.3.2.2.2 In the event that either Party believes that a Material Adverse Ruling has occurred, the Party affected by such Material Adverse Ruling shall provide the other Party a good faith calculation together with information supporting the calculation of the projected effect of the Material Adverse Ruling and include such calculation and the cost information supporting the calculation with the Notice of Termination. If the non-terminating Party notifies the other Party, within twenty (20) Days following the date that such Notice of Termination is given, of its good faith objection to the calculation or the cost information supporting the calculation of the projected effect of the Material Adverse Ruling, then the Parties shall, within thirty (30) Days following the date that such Notice of Termination is given (the “Resolution Period”), attempt to resolve their differences with respect to the calculation or the cost information supporting such calculation. If, at the conclusion of the Resolution Period, the Parties are not in agreement with respect to the calculation or cost information supporting the calculation, then PriceWaterhouseCoopers, or such other nationally recognized accounting firm that is not then the independent auditor for either Party or any of its Affiliates or predecessors and is selected by mutual agreement of the Parties (the “Neutral Auditors”), shall be engaged within ten (10) Days after the expiration of the Resolution Period to review the calculation and the cost information supporting the calculation and to make an independent determination as to whether the Material Adverse Ruling meets the materiality standard set forth in Section 2.3.2.2(c)(1) or (c)(2), as applicable. If the Neutral Auditors require any additional information, records, or internal analysis to make a determination as to whether the Material Adverse Ruling meets the materiality standard set forth in Section 2.3.2.2(c)(1) or (c)(2), as applicable, the Party in possession of such information, records or internal analysis will provide it to the Neutral Auditors. Each Party agrees to execute, if requested by the Neutral Auditors, a reasonable engagement letter, including customary indemnities. All fees and expenses relating to the work to be performed by the Neutral Auditors shall be borne one-half (1/2) by the terminating Party and one-half (1/2) by the non-terminating Party. The Neutral Auditors shall act as an arbitrator to determine, based upon its independent review, whether the Material Adverse Ruling meets the materiality standard set forth in Section 2.3.2.2(c)(1) or (c)(2), as applicable. The Neutral Auditors’ determination shall be made within thirty (30) Days of their selection, shall be set forth in a written statement delivered to both Parties and shall be final, binding and conclusive. If the Neutral Auditors’ determine the materiality standard set forth in Section 2.3.2.2(c)(1) or (c)(2), as applicable, is not met, the Notice of Termination shall be null and void. If the Neutral Auditors’ determine the materiality standard set forth in Section 2.3.2.2(c)(1) or (c)(2), as applicable, is met, the Notice of Termination shall be effective in accordance with its terms. The initiation of the dispute resolution process described in this Section 2.3.2.2.2, shall not toll or otherwise delay running of the twenty-four (24) Month time period set forth in the Notice of Termination, unless the Neutral Auditors’ find that the materiality standard set forth in Section 2.3.2.2(c)(1) or (c)(2), as applicable, is not met. The procedure set forth in this Section 2.3.2.2.2 shall be the exclusive means for the Parties to resolve any dispute as to whether a Material Adverse Ruling meets the materiality standard set forth in Section 2.3.2.2(c)(1) or (c)(2). If a Party gives a Notice of Termination based on its good faith

contention of the occurrence of a Material Adverse Ruling that meets the materiality standard set forth in Section 2.3.2.2(c)(1) or (c)(2), as applicable, and the Neutral Auditors subsequently determine that such materiality standard has not been met, such Party shall not be in default under this Agreement solely because it gave such Notice of Termination.

2.3.2.3 Early Termination for Failure of Condition Precedent . This Agreement may be terminated for failure of a condition precedent in accordance with Section 3.5.2.2 or Section 3.5.3.

2.3.2.4 Early Termination Due to Implementation of Retail Competition . Upon the date of enactment of a Law providing for implementation of retail electric service competition on a comprehensive basis in the State of North Carolina, the Parties shall enter into negotiations with the goal of reaching agreement on amendments to this Agreement to provide for the continuation of the purchase and sale of electric capacity and energy and the provision of Scheduling Agent Services provided for in this Agreement after the commencement of such retail electric service competition. If the Parties are not able to reach agreement by the latter to occur of (i) the date that is ninety (90) Days after the date of enactment of such Law or (ii) the date that is twenty-four (24) Months prior to the commencement of such retail electric service competition in the State of North Carolina, then this Agreement shall terminate automatically on the date such retail electric service competition commences in the State of North Carolina without the need for either Party to give notice.

2.3.2.5 Early Termination Due to Plant Calculation . In the event that the Annual Percentage calculated in Attachment 7-9 is positive for two (2) consecutive Years, and the absolute value of such percentage is greater than ten percent (10%) then EMC may, within twenty (20) Days after the date in such second (2nd) consecutive Year that Duke provides the calculation of the Annual Percentage pursuant to Section 7.3.2.4, give Duke Notice of Termination to terminate this Agreement effective on 23:59:59 of the last Day of Month that is twenty-four (24) Months after the Month in which the Notice of Termination is given. In the event that the Annual Percentage calculated in Attachment 7-9 is negative for two (2) consecutive Years, and the absolute value of such percentage is greater than ten percent (10%) for any two (2) consecutive Years, then Duke may, within twenty (20) Days after the date in such second (2nd) consecutive Year that Duke provides the calculation of the Annual Percentage pursuant to Section 7.3.2.4, give EMC Notice of Termination to terminate this Agreement effective on 23:59:59 of the last Day of Month that is twenty-four (24) Months after the Month in which the Notice of Termination is given. If a Party fails to give Notice of Termination within twenty (20) Days after Duke provides the calculation of the Annual Percentage pursuant to Section 7.3.2.4 for such second (2nd) consecutive Year, it shall have permanently waived its right to terminate this Agreement under this Section based on the Annual Percentage for such two (2) consecutive Years; provided, that nothing in this Section 2.3.2.5 shall affect any Party’s termination rights under Sections 2.3.2.1, 2.3.2.2, 2.3.2.3, 2.3.2.4 or 2.3.2.6.

such ninety (90) Day period; provided, however, if the Claiming Party has used and continues to use all Commercially Reasonable Efforts to remedy, cure or mitigate the event of Force Majeure, then the Non-Claiming Party’s right to give Notice of Termination shall be suspended for so long as the Claiming Party continues to use Commercially Reasonable Efforts to remedy, cure or mitigate the event of Force Majeure.

2.3.3 Form of Notice of Termination . Notice of Termination made pursuant to Sections 2.2 or 2.3 shall be given in accordance with Section 16.22 and shall state (i) the date of termination being effectuated, and (ii) the provision of this Agreement under which termination is being effectuated and the basis for the termination. Except as otherwise provided in this Section 2.3.3, the Notice of Termination is effective when it is deemed given in accordance with Section 16.22. Once the Notice of Termination is given to a Party, it shall not be deemed amended, modified, or otherwise revoked for any reason (other than a determination by the Neutral Auditors pursuant to Section 2.3.2.2.2 that the materiality standard is not met) unless such amendment, modification, or revocation is mutually agreed to by both Parties in writing or unless the Parties reach agreement in accordance with Section 2.3.2.2(a). Upon receipt of the Notice of Termination, the non-terminating Party shall acknowledge receipt in writing sent in accordance with Section 16.22 within five (5) Business Days of the receipt of the Notice of Termination. Acknowledgment of a Notice of Termination is a courtesy and shall not influence the effectiveness of the termination. Failure to utilize a method specified in Section 16.22 shall not influence the effectiveness of the termination if the Notice of Termination is actually received by the Chief Executive Officer of the non-terminating Party within thirty (30) Days of the date of the Notice of Termination, in which case the Notice of Termination shall be effective on the date that the Notice of Termination is actually received by the Chief Executive Officer of the non-terminating Party.

2.4 Absolute Nature of Termination . Both Parties hereby acknowledge, warrant, and agree that TERMINATION OF THIS AGREEMENT FOR ANY REASON PROVIDED FOR AND PERMITTED UNDER THIS AGREEMENT IS ABSOLUTE AND FOREVER EXTINGUISHES ANY AND ALL OBLIGATIONS EXISTING UNDER THIS AGREEMENT FOR (A) DUKE TO PLAN OR PROCURE RESOURCES TO SERVE EMC, OR TO PROVIDE ANY SERVICE OR PRODUCT TO EMC, (B) EMC TO PURCHASE FROM AND PAY DUKE FOR ANY SERVICES OR PRODUCTS, (C) EMC TO PLAN OR PROCURE RESOURCES TO SERVE DUKE, OR TO PROVIDE ANY SERVICE OR PRODUCT TO DUKE, AND (D) DUKE TO PURCHASE FROM AND PAY EMC FOR ANY SERVICES OR PRODUCTS. Upon termination of this Agreement in accordance with Section 2.2, 2.3, 3.5.2.2, or 3.5.3, each and every obligation of Duke to provide electric energy and capacity and Scheduling Agent Services to EMC, and each and every right of EMC to purchase electric energy and capacity and Scheduling Agent Services from Duke shall cease as a matter of contract and neither Party shall claim or assert any continuing right to continued performance, whether by “rollover,” as an “evergreen” service, or in any other fashion based on this Agreement. By entering into this Agreement, Duke does not commit, and shall not be deemed to have committed, to plan its system to be able to provide any service to EMC beyond the Term, and EMC agrees that it has no claim to any service beyond the Term. EMC shall not at any time oppose any filing by Duke to cancel this Agreement as a rate schedule under the Federal Power Act concurrently with, or subsequently to, the termination of this Agreement as a contract in accordance with Section 2.2, 2.3, 3.5.2.2, or 3.5.3. The Parties acknowledge, warrant, and agree

that it is the express intention of the Parties that no action by any Governmental Authority may override the terms of this Section 2.4 of this Agreement, and that should any Governmental Authority take any action purporting to, or that might be claimed to, override the terms of this Section 2.4, either directly or indirectly, EMC shall not make any claim or assert any right based on or relying on such Governmental Authority action in any manner that conflicts with or frustrates the terms of Section 2.4 of this Agreement.

Article 3

Conditions Precedent to the Commencement Date

3.1 Conditions Precedent to Duke’s Obligations . The obligation of Duke to commence sales of electric energy and capacity and purchases of electric energy and to provide Scheduling Agent Services under this Agreement is subject to the satisfaction or waiver at least thirty (30) Days prior to the Commencement Date (except that Duke may undertake certain preliminary activities in advance of the Commencement Date) of the following conditions:

(a) The representations and warranties of EMC set forth in Sections 16.1.1 and the covenants of EMC set forth in Section 16.1.2 shall be true and correct.

(b) FERC shall have issued an order accepting or approving this Agreement for filing and permitting it to become effective as filed without modification, suspension, investigation or other condition (including setting this Agreement, or part thereof, for hearing) unacceptable to Duke.

(c) Neither the NCUC nor the PSCSC shall have issued an Adverse Ruling. For purposes of this Section 3.1(c) only, “Adverse Ruling” means an order or ruling issued by the NCUC or PSCSC (i) which disapproves or rejects this Agreement, or (ii) generally applicable to electric utilities subject to the jurisdiction of the NCUC or PSCSC, as applicable, in which the NCUC or PSCSC disapproves or rejects the use of system average cost accounting for wholesale contracts.

(d) NCEMC shall have received notice and acknowledged EMC’s designation of Duke as EMC’s Scheduling Agent.

(e) EMC shall have given notice to MSCG terminating the Scheduling Services Agreement.

(f) The systems and operational equipment required for Duke to provide and receive service under this Agreement have been installed or otherwise put in place, tested satisfactorily, and are fully functional.

(g) Transmission Provider shall have received notice and acknowledged EMC’s designation of Duke as EMC’s Scheduling Agent and Purchasing - Selling Entity.

(h) MSCG shall have received notice and acknowledged EMC’s designation of Duke as EMC’s Scheduling Agent and Purchasing - Selling Entity.

(i) The Parties shall have agreed upon procedures so that Duke may test whether the EMC Demand Side Management Resource Programs meet the standards and requirements specified for such programs under the rate schedule provisions or riders for Duke’s Demand Side Resource Management Programs then-currently approved and on file with the NCUC.

3.2 Conditions Precedent to EMC’s Obligations . The obligation of EMC to commence purchases of electric energy and capacity and Scheduling Agent Services and sales of electric energy under this Agreement is subject to the satisfaction or waiver at least thirty (30) Days prior to the Commencement Date (except that EMC may undertake certain preliminary activities in advance of the Commencement Date) of the following conditions:

(a) The representations and warranties of Duke set forth in Section 16.1.1 and the covenants of Duke set forth in Section 16.1.2 shall be true and correct.

(b) The RUS shall have approved this Agreement without modification, suspension, investigation or other condition unacceptable to EMC.

(d) The Transmission Provider shall have qualified this Agreement as a Network Resource.

(e) The systems and operational equipment required for EMC to provide and receive service under this Agreement have been installed or otherwise put in place, tested satisfactorily, and are fully functional.

(f) Transmission Provider shall have received and acknowledged EMC’s designation of Duke as Scheduling Agent and Purchasing - Selling Entity.

(g) MSCG shall have received notice and acknowledged EMC’s designation of Duke as EMC’s Scheduling Agent and Purchasing - Selling Entity.

(h) The Parties shall have agreed upon procedures so that Duke may test whether the EMC Demand Side Management Resource Programs meet the standards and requirements specified for such programs under the rate schedule provisions or riders for Duke’s Demand Side Resource Management Programs then-currently approved and on file with the NCUC.

(i) EMC and Carolina Power & Light Company d/b/a Progress Energy Carolinas, Inc. (“CP&L”) shall have each executed and delivered an agreement under which CP&L is obligated during the term to deliver electric capacity and energy and to provide scheduling agent services to meet the demands imposed on EMC by its retail customers that are located within EMC’s Service Area which constitute Non-Duke Control Area Load and each of the conditions precedent contained in such an agreement, whether applicable to EMC or CP&L, have either been satisfied or waived by the respective party.

3.3 Notice of Satisfaction of Conditions Precedent . Each Party shall use Commercially Reasonable Efforts to satisfy its conditions precedent (as described in Section 3.1 for Duke and Section 3.2 for EMC) on or before July 31, 2006, or as soon as reasonably practicable thereafter. EMC shall provide Duke with written notice promptly following the satisfaction or waiver of all of the conditions precedent to EMC’s obligations as described in Section 3.2. Duke shall provide EMC with written notice promptly following the satisfaction or waiver of all of the conditions precedent to Duke’s obligations as described in Section 3.1, other than the condition precedent specified in Section 3.1(e). In order for the condition precedent specified in Section 3.1(e) to be satisfied, subsequent to the later of the date of EMC’s receipt of Duke’s notice or the date of Duke’s receipt of EMC’s notice, EMC shall, no later than thirty (30) Days prior to the Commencement Date, give notice to MSCG that the Scheduling Services Agreement shall be terminated on the Commencement Date. A condition precedent shall not be deemed to have been satisfied or waived prior to the date that the notice provided for in this Section 3.3 is received by the other Party.

3.4 Waiver of Condition Precedent .

3.4.1 Waiver by Duke . In the event that any of the foregoing conditions to the obligations of Duke contained in Section 3.1 shall fail to be satisfied, Duke may elect, in its sole discretion, to consummate this Agreement despite such failure, in which event Duke shall be deemed to have waived any claim for damages, losses or other relief arising from or in connection with such failure, unless otherwise agreed in writing and executed by the Parties. Duke may not waive the condition of approvals set forth in Section 3.1(b).

3.4.2 Waiver by EMC . In the event that any of the foregoing conditions to the obligations of EMC contained in Section 3.2 shall fail to be satisfied, EMC may elect, in its sole discretion, to consummate this Agreement despite such failure, in which event EMC shall be deemed to have waived any claim for damages, losses or other relief arising from or in connection with such failure, unless otherwise agreed in writing and executed by the Parties. EMC may not waive the condition of approvals set forth in Section 3.2(b).

3.4.3 Waiver by other Party . Any waiver by a Party of the other Party’s conditions precedent shall be in writing, and shall identify the condition precedent that such Party is waiving.

3.5 Commencement of Service; Failure of Condition Precedent .

3.5.1 Commencement of Service .

3.5.1.1 If all of the conditions precedent specified in Sections 3.1 and 3.2 have been satisfied or waived on or before July 31, 2006, then the Commencement Date shall occur on September 1, 2006, without the need for either Party to provide notice.

3.5.1.2 If all of the conditions precedent specified in Sections 3.1 and 3.2 are satisfied or waived during the period between August 1, 2006, and November 30, 2006, and service under this Agreement has not commenced pursuant to Section 3.5.2.1, then service under this Agreement shall commence upon the next first Day of a Month which is at least thirty (30) Days after all such conditions have been satisfied.

3.5.2 EMC Options .

3.5.2.1 If all of the conditions precedent specified in Sections 3.1 and 3.2, with the exception of the conditions precedent specified in Section 3.1(b) and/or Section 3.2(b), have been satisfied or waived, then EMC may designate September 1, 2006, October 1, 2006, or November 1, 2006 as the Commencement Date by giving at least thirty (30) Days’ prior written notice to Duke.

3.5.2.2 If service has commenced pursuant to Section 3.5.2.1 prior to November 30, 2006, and the condition precedent specified in Section 3.1(b) and/or Section 3.2(b) has not been satisfied on or before November 30, 2006, then except as provided in Section 3.5.2.3 this Agreement will terminate automatically on December 31, 2006, without the need for either Party to give Notice of Termination and neither Duke nor EMC shall have any obligation, duty or liability to the other arising hereunder under any claim or theory whatsoever.

3.5.2.3 If service has commenced pursuant to Section 3.5.2.1 prior to November 30, 2006, and the condition precedent specified in Section 3.1(b) and/or Section 3.2(b) has not been satisfied on or before November 30, 2006, then EMC shall have the option of continuing to receive service hereunder beyond December 31, 2006 until either August 31, 2007, February 28, 2008, or August 31, 2008. EMC may exercise such option by giving notice to Duke of its exercise of such option no later than December 1, 2006. Such notice shall be referred to herein as the “Option Notice”. EMC’s Option Notice shall specify whether EMC elects to receive service hereunder until August 31, 2007, February 28, 2008, or August 31, 2008. The period of such service that EMC elects pursuant to such option (whether January 1, 2007 - August 31, 2007; January 1, 2007 – February 28, 2008; or January 1, 2007 - August 31, 2008) shall be referred to herein as the “Option Period”. In the event that EMC exercises its option under this Section 3.5.2.3, then during the Option Period EMC shall be subject to the charges and credits set forth in Sections 3.5.2.3.1, 3.5.2.3.2, 3.5.2.3.3, 3.5.2.3.4, and 3.5.2.3.5, as applicable, and in Section 7.1 in lieu of the charges set forth in Section 7.2; provided, that during the Option Period the demand charges set forth in Section 7.1.4 shall be modified as set forth in Sections 3.5.2.3.1, 3.5.2.3.2, or 3.5.2.3.3, as applicable, depending upon the Option Period selected by EMC. In the event that EMC exercises its option under this Section 3.5.2.3, then notwithstanding the provisions of Section 3.5.2.2, this Agreement will terminate automatically on the last day of the Option Period, without the need for either Party to give Notice of Termination and neither Duke nor EMC shall have any obligation, duty or liability to the other arising hereunder under any claim or theory whatsoever for service beyond such date. EMC’s exercise of such option shall not serve to modify any other provision of the Agreement.

3.5.2.3.1 In the event that EMC exercises its option pursuant to Section 3.5.2.3, and the Option Period is January 1, 2007 – August 31, 2007, EMC shall pay to Duke, in addition to the other charges set forth in this Agreement, the Base Annual Capacity Charge set forth in Section 3.5.2.3.4 and the Excess Annual Capacity Charge set forth in Section 3.5.2.3.5. In such event, the Annual Capacity Price under Section 3.5.2.3.4, Annual Capacity Quantity under Section 3.5.2.3.4, and Excess Annual Capacity Price under Section 3.5.2.3.5 during the Option Period shall be as follows:


Annual Capacity Price	$	38.00/kW-Year
Annual Capacity Quantity		23,000 kW
Excess Annual Capacity Price	$	45.60/kW-Year

In addition, the Monthly Demand Rate under Section 7.1.4 during the Option Period shall be $5.45/kW-Month, rather than the rate specified in Section 7.1.4, and the Duke Monthly Energy Charge and EMC Monthly Energy Credit (and other charges and credits under Sections 7.1.5.11, 7.1.5.12, and 7.1.5.13) during the Option Period shall be as set forth in Section 7.1.5.

3.5.2.3.2 In the event that EMC exercises its option pursuant to Section 3.5.2.3, and the Option Period is January 1, 2007 – February 28, 2008, EMC shall pay to Duke, in addition to the other charges set forth in this Agreement, the Base Annual Capacity Charge set forth in Section 3.5.2.3.4 and the Excess Annual Capacity Charge set forth in Section 3.5.2.3.5. In such event, the Annual Capacity Price under Section 3.5.2.3.4, Annual Capacity Quantity under Section 3.5.2.3.4, and Excess Annual Capacity Price under Section 3.5.2.3.5 during the Option Period shall be as follows:


January 1, 2007 - December 31, 2007:

Annual Capacity Price	$	38.00/kW-Year
Annual Capacity Quantity		23,000 kW
Excess Annual Capacity Price	$	45.60/kW-Year

January 1, 2008 – February 28, 2008:

Annual Capacity Price		0
Annual Capacity Quantity		0
Excess Annual Capacity Price		0

In addition, the Monthly Demand Rate under Section 7.1.4 during the Option Period shall be $5.45/kW-Month during 2007 and $5.75/kW-Month during 2008, rather than the rate specified in Section 7.1.4, and the Duke Monthly Energy Charge and the EMC Monthly Energy Credit (and other charges and credits under Sections 7.1.5.11, 7.1.5.12, and 7.1.5.13) during the Option Period shall be as set forth in Section 7.1.5.

3.5.2.3.3 In the event that EMC exercises its option pursuant to Section 3.5.2.3, and the Option Period is January 1, 2007 – August 31, 2008, EMC shall pay to Duke, in addition to the other charges set forth in this Agreement, the Base Annual Capacity Charge set forth in Section 3.5.2.3.4 and the Excess Annual Capacity Charge set forth in Section 3.5.2.3.5. In such event, the Annual Capacity Price under Section 3.5.2.3.4, Annual Capacity Quantity under Section 3.5.2.3.4, and Excess Annual Capacity Price under 3.5.2.3.5 during the Option Period shall be as follows:


January 1, 2007 - December 31, 2007:

Annual Capacity Price	$	38.00/kW-Year
Annual Capacity Quantity		23,000 kW
Excess Annual Capacity Price		$45.60/kW-Year

January 1, 2008 – August 31, 2008:

Annual Capacity Price		$40.00/kW-Year
Annual Capacity Quantity		24,000 kW
Excess Annual Capacity Price	$	48.00/kW-Year

3.5.2.3.4 Base Annual Capacity Charge . The Base Annual Capacity Charge for a Year shall be equal to the product of (i) the Annual Capacity Price for the Year ($/kW-Year) and (ii) the Annual Capacity Quantity for the Year (kW). The Base Annual Capacity Charge for the Option Period shall be billed in accordance with Article 13 in the July 2007 statement and the July 2008 statement, if applicable.

3.5.2.3.5 Excess Annual Capacity Charge . The Excess Annual Capacity Charge for a Year shall be equal to the product of (i) the Excess Annual Capacity Price for the Year ($/kW-Year) and (ii) the Excess Annual Amount for the Year (kW). The Excess Annual Amount for a Year shall be equal to the product of (i) the EMC Excess Annual Capacity Quantity for the Year divided by the EMC Group Combined Excess Annual Capacity Quantity for the Year and (ii) the EMC Group Excess Annual Capacity Quantity for the Year. The Excess Annual Capacity Charge for the Option Period shall be billed in accordance with Article 13 in the September 2007 and the September 2008 statements, if applicable, based on the actual Duke billing data during July and August 2007 and July and August 2008, respectively. A sample calculation is provided in Attachment 3-1.

3.5.2.3.5.1 EMC Excess Annual Capacity Quantity . The EMC Excess Annual Capacity Quantity for a Year shall be equal to the EMC Coincident Peak Demand for the Year minus EMC’s Base Obligation for the Hour in such Year in which the EMC Coincident Peak Demand occurs, minus the Annual Capacity Quantity for the Year. In no event shall the EMC Excess Annual Capacity Quantity be less than zero. The EMC Coincident Peak Demand for a Year shall be equal to the EMC Hourly Demand that is coincident with the maximum integrated sixty (60) minute Duke Schedule 1 Demands during July and August of the Year. The EMC Hourly Demand for an Hour shall be equal to the integrated sixty (60) minute demand of EMC’s Native Load during the Hour.

3.5.2.3.5.2. EMC Group Combined Excess Annual Capacity Quantity . The EMC Group Combined Excess Annual Capacity Quantity for a Year shall be equal to the sum of (i) the EMC Excess Annual Capacity Quantity for the Year as determined in Section 3.5.2.3.5.1 of this Agreement, (ii) the EMC Excess Annual Capacity Quantity for the Year as determined in Section 3.5.2.3.5.1 of the Duke-Blue Ridge Agreement, and (iii) the EMC Excess Annual Capacity Quantity for the Year as determined in Section 3.5.2.3.5.1 of the Duke-Rutherford Agreement.

3.5.2.3.5.3 EMC Group Excess Annual Capacity Quantity . The EMC Group Excess Annual Capacity Quantity for a Year shall be equal to the EMC Group Coincident Peak Demand for the Year, minus the EMC Group’s Base Obligation for the Hour in such Year in which the EMC Group Coincident Peak Demand occurs, minus the EMC Group Annual Capacity Quantity; but in no event shall the EMC Group Excess Annual Capacity Quantity be less than zero. The EMC Group Coincident Peak Demand shall for a Year be equal to the sum of (i) the EMC Coincident Peak Demand for the Year as determined in Section 3.5.2.3.5.1 of this Agreement, (ii) the EMC Coincident Peak Demand for the Year as determined in Section 3.5.2.3.5.1 of the Duke-Blue Ridge Agreement, and (iii) the EMC Coincident Peak Demand for the Year as determined in Section 3.5.2.3.5.1 of the Duke-Rutherford Agreement.

3.5.2.4 Any Option Notice given by EMC pursuant to Section 3.5.2.3 shall be given in accordance with Section 16.22 and shall state the Option Period elected. The Option Notice is effective when it is deemed given in accordance with Section 16.22. Once the Option Notice is given to Duke, it shall not be deemed amended, modified, or otherwise revoked for any reason unless such amendment, modification, or revocation is mutually agreed to by both Parties in writing.

3.5.3 Termination for Failure of Condition Precedent .

3.5.3.1 Subject to the options granted to EMC under Section 3.5.2.1 and 3.5.2.3, in the event that any of the conditions precedent set out in Sections 3.1(a) through (i) and Sections 3.2(a) through (i) are not satisfied or waived on or before November 30, 2006, then this Agreement will terminate automatically on December 31, 2006, without the need for either Party to give Notice of Termination and neither Duke nor EMC shall have any obligation, duty or liability to the other arising hereunder under any claim or theory whatsoever.

Article 4

Sale of Electric Capacity and Energy

4.1 Classification of Services Provided . During the period beginning on the Commencement Date, and continuing through December 31, 2010, or any part thereof in which this Agreement is in effect, Duke shall provide to EMC “FFR Supplemental Service”, as described in Section 4.2. Beginning January 1, 2011, throughout the remainder of the Term of this Agreement, Duke shall provide to EMC “Partial Requirements Service”, as described in Section 4.3.

4.2 FFR Supplemental Service .

4.2.1 Character of FFR Supplemental Service . For each Hour during the period beginning on the Commencement Date, and continuing through December 31, 2010, or any part thereof in which this Agreement is in effect, Duke shall sell and deliver, and EMC shall purchase and receive, all of the electric capacity and energy that EMC requires to serve EMC’s Native Load in excess of EMC’s Base Obligation for such Hour. For example, if EMC’s Native Load during an Hour is 800 MWs, and EMC’s Base Obligation for such Hour is 600 MWs, Duke shall supply and deliver, and EMC shall purchase and receive, 200 MWs of FFR Supplemental Service for such Hour. Duke shall supply and deliver FFR Supplemental Service in a manner that is as firm as, and otherwise comparable with, the manner in which Duke supplies Duke’s Native Load. Duke shall be responsible for maintaining the generation reserves needed to meet its FFR Supplemental Service obligation. Notwithstanding anything in this Agreement to the contrary, Duke shall have no obligation to sell and deliver any electric capacity or energy to EMC that is not required to serve EMC’s Native Load.

4.2.2 Amount of EMC’s Base Obligation . EMC’s Base Obligation for each Hour beginning on the Commencement Date, and continuing through December 31, 2010, or any part thereof in which this Agreement is in effect, shall be as set forth in Attachment 4-1 . Notwithstanding the preceding sentence, EMC’s Base Obligation shall be subject to modification (a) during Light Load Periods in accordance with the provisions of Attachment 4-2 or (b) in accordance with the provisions of Section 5.1.4 and 5.1.5. The amounts set forth on Attachment 4-1 reflect MWs delivered at a Delivery Point.

4.2.3 Scheduling To Meet EMC’s Base Obligation. In order to meet EMC’s Base Obligation, (a) MSCG shall be responsible for scheduling to the Transmission Provider electric energy under the PPA to serve EMC’s Native Load and (b) Duke, acting as Scheduling Agent, shall be responsible for scheduling to the Transmission Provider, in accordance with the provisions of Article 8, electric energy to serve EMC’s Native Load from EMC’s entitlements to the resources described in Section 5.1.3, 5.1.4 or 5.1.5. The total amount of electric energy so scheduled to the Transmission Provider in any Hour to serve EMC’s Native Load beginning on the Commencement Date, and continuing through December 31, 2010, or any part thereof in which this Agreement is in effect, shall be the EMC Scheduled Amount; provided that the EMC Scheduled Amount shall not exceed EMC’s Base Obligation for any such Hour.

4.2.4 Scheduling Shortfall . For each Hour beginning on the Commencement Date, and continuing through December 31, 2010, or any portion thereof in which this Agreement is in

effect, if, for any reason, including a Force Majeure as that term is defined herein or a “force majeure”, “uncontrollable force”, or a similar term defined in a third-party agreement, but not including Duke’s unexcused failure to comply with the provisions of Article 8, the EMC Scheduled Amount is less than EMC’s Base Obligation for any Hour, there shall be a “Scheduling Shortfall” in the amount equal to the difference between EMC’s Base Obligation and the EMC Scheduled Amount in such Hour (“Scheduling Shortfall Amount”). For any Hour that Duke receives information or a notice pursuant to Section 8.4.8 that there will be or has been a Scheduling Shortfall, Duke shall use Commercially Reasonable Efforts to procure and supply electric energy in a quantity sufficient to supply the Scheduling Shortfall Amount for such Hour (“Replacement Energy”). In the event that, through the exercise of Commercially Reasonable Efforts, Duke procures Replacement Energy from a third party for resale to EMC, EMC shall pay Duke for the total cost incurred by Duke to purchase and deliver the Replacement Energy. Duke’s curtailment of a Non-Firm Sale shall constitute a procurement of Replacement Energy from a third party and the total cost incurred by Duke shall be (i) the foregone sales price for the Non-Firm Sale curtailed and (ii) if applicable, any charges imposed for changes to schedules for the sale of electric energy. In the event that Duke supplies Replacement Energy from its own resources, EMC shall pay Duke for such Replacement Energy an amount equal to one hundred ten percent (110%) of Duke’s System Incremental Cost in supplying such Replacement Energy. The total charges for Replacement Energy for a Month, as determined by this Section 4.2.4, shall constitute the Monthly Replacement Energy Charge.

4.2.4.1 It is expressly understood that Section 4.2.4 shall not be construed or interpreted to (i) require Duke to curtail any Firm Sales in order to supply Replacement Energy to EMC, (ii) to curtail any Non-Firm Sales except as set forth in Section 4.2.6 in order to supply such Replacement Energy to EMC, (iii) impose upon Duke any responsibility for providing Replacement Energy for a Scheduling Shortfall that occurs after the Transmission Provider’s deadline for scheduling transmission service required for the delivery of such Replacement Energy, or (iv) affect in any way EMC’s rights and obligations under its Network Integration Transmission Service Agreement.

4.2.4.2 In the event that there is or is expected to be a Scheduling Shortfall in connection with (a) EMC or its Scheduling Agent having received notice (and in the event EMC receives notice providing Duke with evidence of such notice) of, or (b) pursuant to Section 8.4.8 Scheduling Agent having received notice of either (i) the occurrence of a “force majeure” event under the PPA, as defined in Section 4.2.4.3, or (ii) the temporary impairment of generating resources underlying the WPSA or other resources to which EMC may have an entitlement pursuant to Section 5.1.3, 5.1.4 or 5.1.5, such that all or a portion of EMC’s entitlements to electric energy under such agreements are or will be temporarily unavailable to EMC, then EMC may request Duke to sell electric capacity and energy to EMC for the expected duration of such Scheduling Shortfall. In the event that EMC makes such a request, Duke shall exercise Commercially Reasonable Efforts to offer to supply electric capacity and energy to EMC under rates, terms, and conditions that Duke determines to be commercially reasonable. If the Parties reach agreement on such a sale, then Duke shall sell and deliver and EMC shall purchase and receive the electric energy and such electric energy shall be included in EMC Scheduled Amount.

4.2.4.3 For purposes of Section 4.2.4.2, the term “force majeure” means an event or circumstance that: (i) prevents the party claiming to be affected by it from performing its obligations in whole or in part; (ii) is not within the reasonable control of the claiming party, or the result of the negligence of the claiming party, and (iii) by the exercise of due diligence, the claiming party is unable to overcome in a commercially reasonable manner, and, without limiting the scope of the definition, includes acts of God, or the public enemy, or insurrection, riot, acts of terrorism, civil disturbance or disorder, strikes, fire, earthquakes, floods, storms or other natural disasters, or actions or restraints by court order or governmental authority or arbitration award (so long as the claiming party has not sought or has opposed, to the extent reasonable, such actions or restraints). It is expressly acknowledged that transmission service interruptions or curtailments imposed by a transmission provider in response to transmission capacity or availability shortages shall not be “force majeure” events or circumstances for purposes of this Section 4.2.4.3.

4.2.5 EMC PPA Obligation . EMC shall retain all of its rights and obligations under the PPA, including the obligation to pay all costs incurred under the PPA.

4.2.6 EMC Obligation to Curtail Load . During any Hour in which there is a Scheduling Shortfall, and either (i) Duke does not replace such electric energy in accordance with Section 4.2.4 or (ii) EMC has not made, or does not have in place, arrangements to replace such electric energy, EMC shall curtail an amount of EMC’s Native Load equal to the Scheduling Shortfall Amount; provided, however, Duke shall exercise Commercially Reasonable Efforts within the time constraints that exist to first call upon any available EMC Demand Side Management Resource Program that would not otherwise be called upon absent the Scheduling Shortfall and then if necessary curtail Non-Firm Sales to the extent of the Scheduling Shortfall before requiring EMC to curtail EMC’s Native Load pursuant to this Section 4.2.6. Any such EMC Native Load that has been curtailed shall be restored when the Scheduling Shortfall is no longer occurring or when the Scheduling Shortfall has been replaced either by electric energy supplied (a) by Duke in accordance with Section 4.2.4 or this Section 4.2.6 or (b) under arrangements made by EMC with third parties.

4.3 Partial Requirements Service .

4.3.1 Character of Partial Requirements Service . For each Hour during the period beginning on January 1, 2011, and continuing through the termination of this Agreement, Duke shall sell and deliver, and EMC shall purchase and receive, all of the electric capacity and energy that EMC requires to serve EMC’s Native Load in excess of the EMC Contract Resources. Duke shall be responsible for maintaining the generation reserves necessary to meet this obligation. Duke shall supply Partial Requirements Service in a manner that is as firm as, and otherwise comparable with, the manner in which Duke supplies Duke’s Native Load. Notwithstanding anything in this Agreement to the contrary, Duke shall have no obligation to sell and deliver any electric capacity or energy to EMC that is not required to serve EMC’s Native Load.

4.3.2 Scheduling of EMC Contract Resources To Serve EMC Native Load . For each Hour beginning on January 1, 2011, and continuing through the Term of this Agreement, EMC’s contractual entitlement to electric energy from the Dispatched Combined Cycle Resources and from the Baseload Resources shall be scheduled in accordance with the provisions of Sections 4.3.3 and 4.3.4, respectively.

4.3.3 Scheduling of the Combined Cycle Resources . Duke may schedule, in accordance with Attachment 4-3 and Article 8, each of the Combined Cycle Resources pursuant to Duke’s economic dispatch as necessary to serve Duke’s total electric energy obligations. Duke shall make no adverse distinction against the Combined Cycle Resources in determining the dispatch order of Duke’s Generation System and the Combined Cycle Resources. The Combined Cycle Resources that Duke schedules pursuant to economic dispatch shall be referred to as the “Dispatched Combined Cycle Resources”. Except as provided in Section 4.3.3.1 and Section 4.3.3.2, EMC shall be solely responsible for all costs associated with the Combined Cycle Resources.

4.3.3.1 Duke shall not be obligated to pay for any costs that EMC incurs as a result of Duke’s dispatch of the Combined Cycle Resources to the extent that Duke’s dispatch of such Combined Cycle Resources is for the purpose of serving Duke’s Native Load and, during any Year, Duke’s dispatch of a Combined Cycle Resource for that purpose does not exceed an Annual Capacity Factor of twenty percent (20%). In the event and at such time during a Year that Duke’s dispatch of a Combined Cycle Resource to serve Duke’s Native Load exceeds an Annual Capacity Factor of twenty percent (20%), Duke shall pay EMC, in the manner and time provided for in Article 13, the additional Energy Cost that EMC incurs as a result of Duke’s dispatch of such Combined Cycle Resource for the remainder of the Year. For example, if a Dispatched Combined Cycle Resource has a generating capacity of one hundred (100) MWs during a Year and, as of 11:59:59 p.m. on November 30 of such Year, Duke has dispatched such resource for 175,200 MWhs for the purpose of serving Duke’s Native Load, Duke shall reimburse EMC for the Energy Costs that EMC incurs in December of such Year as a result of Duke’s dispatch of such Dispatched Combined Cycle Resource. For the purpose of this Section 4.3.3.1, “Annual Capacity Factor” means the total amount of electric energy generated by a Dispatched Combined Cycle Resource for the purpose of serving Duke’s Native Load during a Year divided by the product of (a) the total generating capacity of such Dispatched Combined Cycle Resource and (b) 8,784 (during a leap year) or 8,760 (during a Year other than a leap year), multiplied by one hundred percent (100%).

4.3.3.2 In the event that Duke’s dispatch of one or more of the Combined Cycle Resources is for any purpose other than to serve Duke’s Native Load, Duke shall pay EMC, in the manner and time provided for in Article 13, the additional Energy Cost that EMC incurs as a result of Duke’s dispatch of such Combined Cycle Resource(s).

4.3.3.3 For purposes of Sections 4.3.3.1 and 4.3.3.2, “Energy Cost” means, with respect to any Dispatched Combined Cycle Resource, all variable costs incurred by EMC that are associated with the production of electric energy under the WPSA, including the cost of fuel, start charges, and any other variable charges incurred by EMC under the WPSA in connection with the electric energy dispatched by Duke from such Combined Cycle Resource regardless of NCEMC’s actual generating cost or NCEMC’s contractual source of the electric energy.

4.3.4 Scheduling of Baseload Resources . Duke shall schedule, in accordance with Article 8, all of the Baseload Resources to the full extent that EMC’s entitlement to such resources are available to EMC and such electric energy shall be used to serve EMC’s Native Load. EMC shall be solely responsible for all costs associated with the Baseload Resources. The Baseload Resources that Duke schedules pursuant to this Section 4.3.4 shall be referred to as “Dispatched Baseload Resources”.

4.4 Excepted Load . Notwithstanding anything to the contrary herein, Duke shall have no obligation to supply electric capacity or energy required by EMC to serve Excepted Load. Excepted Load shall consist of EMC load that is either (a) Non-Conforming Load or (b) Non-Duke Control Area Load. Non-Conforming Load shall consist of (i) EMC load resulting from the merger of EMC with another electric membership corporation or other entity (except to the extent such load was, at the time of the merger, already being served by Duke under an agreement substantially similar to this Agreement), and (ii) EMC wholesale load. Non-Conforming Load shall also consist of discrete EMC load (a) to which electric service from EMC shall have commenced after the Effective Date, (b) that has a projected peak demand in excess of twenty-five (25) MW for the Year in which electric service from the EMC commences, and (c) which is projected to change within a one-minute period by a significant quantity on a recurring basis due to the nature of the retail customer’s operations ( e.g. , without limitation, an arc furnace).

4.5 Good Title . Electric energy that is delivered by Duke to EMC shall be free and clear of all liens, Claims, and encumbrances at the Delivery Points, where title to electric energy provided by Duke hereunder shall transfer to EMC. Electric energy that is delivered by EMC to Duke shall be free and clear of all liens, Claims, and encumbrances at the point where title to the electric energy is transferred to Duke.

4.6 Power Quality . All electric energy provided hereunder at the point of delivery shall be three (3) phase, sixty (60) hertz, and at system nominal voltages.

Article 5

EMC Resources

5.1 EMC Contract Resources (Commencement Date - December 31, 2010) .

5.1.1 Identification of Resources . Except as provided in Section 5.4.1, EMC’s Contract Resources during the period commencing on the Commencement Date, and continuing through December 31, 2010, or any part thereof in which this Agreement is in effect, shall consist of EMC’s entitlement to electric capacity and energy under the PPA and such additional generation or purchased power resources or entitlements as EMC may acquire pursuant to Sections 5.1.3, 5.1.4 and 5.1.5. The FFR Resource is listed in Attachment 4-1 . Except as provided in this Section 5.1.1, EMC shall not, without first obtaining Duke’s prior written consent, enter into any other contracts for, or acquire any ownership interest in or contractual entitlement to, any additional electric generating resources or electric capacity or energy under which electric capacity and energy would be used to serve EMC’s Native Load during the Term.

5.1.2 Changes to FFR Resources . During the period commencing on the Commencement Date, and continuing through December 31, 2010, or any part thereof in which this Agreement is in effect, EMC shall not: (a) take any action that would materially affect the quantity or quality of MSCG’s service obligations under the PPA without first obtaining Duke’s prior written consent, or (b) agree to any modification to provisions of the PPA or the WPSA that would increase or decrease EMC’s entitlement to electric capacity or energy under such agreements and for which EMC’s consent is required (except as provided in Section 5.1.4) without first obtaining Duke’s consent to such modification.

5.1.3 Resource Impairment . In the event that all or a portion of the FFR Resource, or any other EMC Contract Resource, is terminated or becomes permanently impaired, EMC shall acquire, at EMC’s expense, a substitute resource (backed by reserves in an amount equal to that required under Duke’s Generation Planning Practices) that is of substantially equivalent size and comparable reliability to the EMC Contract Resource, or portion thereof, that such substitute is replacing.

5.1.4 New Catawba Resource . In the event that NCEMC acquires all or part of Saluda River Electric Cooperative’s existing ownership interest in the Catawba Nuclear Station, and sells, allocates or transfers a percentage of that entitlement with such entitlement being made available throughout the Year to EMC (through a modification of the WPSA or pursuant to a new contract), EMC’s Base Obligation shall be increased by an amount equal to the amount of the entitlement so acquired by EMC. Upon Duke’s request, EMC shall provide evidence reasonably satisfactory to Duke demonstrating that such entitlement in the Catawba Nuclear Station is backed by sufficient and reliable electric system generating reserves. Duke shall limit such requests to one (1) request per Year; provided, that if Duke reasonably believes that the sufficiency or reliability of the electric system generating reserves backing EMC’s entitlement in the Catawba Nuclear Station may have changed since Duke’s last such request, this limitation shall not apply. In the event that EMC fails to demonstrate that its entitlement in the Catawba Nuclear Station is backed by sufficient and reliable generating reserves, Duke shall supply, and EMC shall purchase, such reserves in an amount equal to that required under Duke’s Generation

Planning Practices. The Monthly charge for such reserves shall be equal to the product of the amount of reserves (as determined under the prior sentence) supplied by Duke to EMC at the then-applicable Monthly Demand Charge. Duke’s provision and EMC’s purchase of such reserves shall not affect the determination of EMC’s Base Obligation. This Monthly charge shall be billed by Duke in accordance with the provisions of Article 13.

5.1.4.1 In the event that NCEMC purchases electric capacity and energy from Duke in lieu of NCEMC’s acquisition of all or a part of Saluda River Electric Cooperative’s existing ownership interest in the Catawba Nuclear Station as provided in Section 5.1.4, and NCEMC sells, allocates or transfers a portion of such electric capacity and energy to EMC (through a modification of the WPSA or pursuant to a new contract), EMC’s Base Obligation shall be increased by an amount equal to the amount of the electric capacity and energy so acquired by EMC.

5.1.5 Non-Consent Modification of EMC’s Contract Resources . In the event that EMC’s entitlements to electric capacity and energy are reduced in accordance with Section 2.9(b) or Section 2.9(c) of the WPSA, the amount of the EMC’s Base Obligation shall not be affected and the provisions of Section 4.2.4.2 shall apply, except that if the Parties are unable to reach agreement as to the rates, terms and conditions under which Duke would sell electric capacity and energy to EMC, the provisions of Section 5.1.3 shall apply. EMC shall provide written notice to Duke as soon as reasonably practicable after EMC becomes aware of any modification to EMC’s entitlement to electric capacity and energy under the WPSA pursuant to this Section 5.1.5. In the event that EMC’s entitlements to electric capacity and energy are increased in accordance with Section 2.9(b) or Section 2.9(c) of the WPSA, then, prior to the effective date of such increase, EMC may elect either to (a) increase EMC’s Base Obligation by the same amount and to the same extent as EMC’s entitlements to electric capacity and energy are increased, or (b) make arrangements for the sale of EMC’s entitlements to such electric capacity and energy to a third party or to Duke. If EMC fails to complete the arrangements described in (b) of the preceding sentence by the effective date of the increase in entitlements, then, as of the effective date of the increase in entitlements, the EMC’s Base Obligation automatically will be increased as described in (a) of the preceding sentence.

5.2 EMC Contract Resources (January 1, 2011 - Termination of Agreement) .

5.2.1 Identification of Contract Resources . Except as provided in Section 5.4.1, EMC’s Contract Resources during the period January 1, 2011, through the termination of this Agreement shall consist of EMC’s entitlements to electric capacity and energy under the contracts listed in Attachment 4-3 and such additional generation or purchased power resources or entitlements as EMC may acquire pursuant to Sections 5.2.3, 5.2.4, and 5.2.5. EMC’s entitlements under the contracts that are listed in Attachment 4-3 shall be referred to as the Partial Requirements Resources. Partial Requirements Resources consist of two (2) categories of entitlements: Baseload Resources and Combined Cycle Resources. The amount and the material cost and operational terms and conditions of the Baseload Resources and Combined Cycle Resources shall be as set forth in Attachment 4-3 , subject to modification in accordance with Sections 5.2.3 and 5.2.4. Except as provided in this Section 5.2.1, EMC shall not, without first obtaining

Duke’s prior written consent, enter into any other contracts for, or acquire any ownership interest in or contractual entitlement to, any additional electric generating resources or electric capacity or energy under which electric capacity and energy would be used to serve EMC’s Native Load during the Term.

5.2.1.1 Extension of WPSA . Consistent with the provisions of Section 5.2.2, EMC shall have the right, without the prior consent of Duke, to extend the term of the WPSA under substantially the same terms and conditions as exist at the time that EMC seeks to extend the term of the WPSA. If EMC extends the term of the WPSA in accordance with this Section 5.2.1.1, the EMC Contract Resources listed in Attachment 4-3 shall be deemed to be changed accordingly.

5.2.2 Changes To Partial Requirements Resources . Commencing January 1, 2011, through the termination of this Agreement, EMC shall not (a) take any action that would materially affect the quantity or quality of EMC’s entitlement to electric capacity and energy from the Partial Requirements Resources without first obtaining Duke’s prior written consent, or (b) agree to any modification to provisions of the WPSA that would increase or decrease EMC’s entitlement to electric capacity or energy under such agreement and for which EMC’s consent is required (except as provided in Section 5.2.4) without first obtaining Duke’s consent to such modification.

5.2.2.1 Modifications Effective After Termination . Notwithstanding the provisions of Section 5.2.2, EMC shall be permitted to agree to any resource modification under the WPSA without obtaining Duke’s consent to the extent that such resource modification will become effective after the Term; provided, that if such resource modification will become effective prior to the end of the Term, EMC’s Partial Requirements Resources and Duke’s obligation to provide Partial Requirements Service shall not be modified prior to the date that this Agreement is terminated unless Duke consents to such modification.

5.2.2.2 Sufficiency of Reserves . Upon Duke’s request, EMC shall provide evidence reasonably satisfactory to Duke demonstrating that each of EMC’s Partial Requirements Resources is backed by sufficient and reliable electric system generating reserves. Duke shall limit such requests to one (1) request per Year with respect to any Partial Requirements Resource; provided, that if Duke reasonably believes that the sufficiency or reliability of the electric system reserves backing any Partial Requirements Resource may have changed since Duke’s last such request, this limitation shall not apply with respect to that Partial Requirements Resource. In the event that EMC fails to demonstrate that its entitlement in a Partial Requirements Resource is backed by sufficient and reliable generating reserves, Duke shall supply, and EMC shall purchase, such reserves in an amount equal to that required under Duke’s Generation Planning Practices. The Monthly charge for such reserves shall be equal to the product of the amount of reserves (as determined under the prior sentence) supplied by Duke to EMC and the then applicable Monthly Demand Charge. This Monthly charge shall be billed by Duke in accordance with the provisions of Article 13. Duke’s provision and EMC’s purchase of such reserves shall not affect the determination of the amount of Partial Requirements Resources, Baseload Resources or Combined Cycle Resources. EMC shall provide written notice to Duke as soon as reasonably practicable after EMC becomes aware of a material change to the seller’s service obligations under the contracts listed in Attachment 4-3 ; provided, that such notice shall be for information purposes only, and shall not affect any other obligations of either Party under this Agreement.

5.2.3 Non-Consent Partial Requirements Resource Modifications . In the event that EMC’s entitlements are modified pursuant to Section 2.9(b) or Section 2.9(c) of the WPSA, EMC’s Partial Requirements Resources shall be modified in the same amount and to the same extent. To the extent that a Partial Requirements Resource is modified pursuant to this Section 5.2.3, and the modification changes EMC’s entitlement in a resource listed as a Baseload Resource in Attachment 4-3 , the amount of such Baseload Resource, as listed in Attachment 4-3 , shall be deemed to be changed accordingly. EMC shall provide written notice to Duke as soon as reasonably practicable after EMC becomes aware of any modification to EMC’s entitlement to electric capacity and energy under the WPSA pursuant to this Section 5.2.3. To the extent that a Partial Requirements Resource is modified pursuant to this Section 5.2.3, and the modification changes EMC’s entitlement in a resource listed as a Combined Cycle Resource in Attachment 4-3 , the amount of such Combined Cycle Resource, as listed in Attachment 4-3 , shall be deemed to be changed accordingly.

5.2.4 New Catawba Resource . In the event that NCEMC acquires all or part of Saluda River Electric Cooperative’s existing ownership interest in the Catawba Nuclear Station, and sells, allocates or transfers a percentage of that entitlement with such entitlement being made available throughout the Year to EMC (through modification of the WPSA or pursuant to a new contract), the entitlement or resource so acquired by EMC shall constitute an additional Partial Requirements Resource, and shall be deemed to be an additional Baseload Resource. Upon Duke’s request, EMC shall provide evidence reasonably satisfactory to Duke demonstrating that such entitlement in the Catawba Nuclear Station is backed by sufficient and reliable electric system generating reserves. Duke shall limit such requests to one (1) request per year; provided, that if Duke reasonably believes that the sufficiency or reliability of the electric system generating reserves backing EMC’s entitlement in the Catawba Nuclear Station may have changed since Duke’s last such request, this limitation shall not apply. In the event that EMC fails to demonstrate that its entitlement in the Catawba Nuclear Station is backed by sufficient and reliable generating reserves, Duke shall supply, and EMC shall purchase, such reserves in an amount equal to that required under Duke’s Generation Planning Practices. The Monthly charge for such reserves shall be equal to the product of the amount of reserves (as determined under the prior sentence) supplied by Duke to EMC and the then-applicable Monthly Demand Charge. This Monthly charge shall be billed by Duke in accordance with the provisions of Article 13. Duke’s provision and EMC’s purchase of such reserves shall not affect the determination of the amount of Partial Requirements Resources, Baseload Resources or Combined Cycle Resources.

5.2.4.1 In the event that NCEMC purchases electric capacity and energy from Duke in lieu of NCEMC’s acquisition of all or a part of Saluda River Electric Cooperative’s existing ownership interest in the Catawba Nuclear Station as provided in Section 5.2.4, and NCEMC sells, allocates or transfers a portion of such capacity and energy to EMC (through a modification of the WPSA or pursuant to a new contract), EMC’s Baseload Resources shall be increased by an amount equal to the amount of the electric capacity and energy so acquired by EMC.

5.2.5 Resource Impairment . In the event that all or a portion of an EMC Contract Resource is terminated or becomes permanently impaired, EMC shall acquire, at EMC’s cost, a substitute resource (backed by reserves in an amount equal to that required under Duke’s Generation Planning Practices) that is of substantially equivalent size and comparable reliability to the EMC Contract Resource, or portion thereof, that such substitute resource is replacing, and that Duke reasonably agrees is sufficiently reliable. EMC’s acquisition of such substitute resource shall not affect the determination of the amount of Partial Requirements Resources, Baseload Resources or Combined Cycle Resources.

5.3 No Duke Obligation for Customer Resources . Unless otherwise explicitly provided in this Agreement, nothing herein shall be interpreted or construed as imposing upon Duke any obligations or liabilities, or for transferring to Duke any EMC obligations or liabilities, under or otherwise pertaining to any EMC Contract Resource, nor shall anything in this Agreement be interpreted or construed as creating or implying any contractual or other relationship between Duke and any other party as to a EMC Contract Resource.

5.4 New Customer Resources . Except as provided in Section 5.4.1, Duke shall have no obligation to amend this Agreement and EMC shall not make an application to FERC requesting that FERC require that any amendment be made to this Agreement, to accommodate any contractual entitlement to and/or ownership interest in or pertaining to any new electric capacity and/or energy resource that EMC may obtain after the Effective Date.

5.4.1 PURPA Resources . Nothing herein shall limit EMC’s right to purchase electric capacity and energy from a Qualifying Facility or other renewable resources pursuant to PURPA (“PURPA Resource”). If, during the Term, EMC purchases electric capacity and energy from a PURPA Resource with a nameplate capacity equal to or greater than one (1) MW, then, for each Month during the period of such purchase: (i) the average hourly integrated electric energy delivered to EMC by such PURPA Resource during the Hours used for determination of the EMC Monthly Demand Quantity determined in accordance with Section 7.1.4.1 or 7.2.4.1 as applicable or used for determination of the Monthly Billing Demand determined in accordance with Section 7.2.6.3.2 or Section 7.3.2.2 increased for losses between the point of measurement of EMC’s Native Load and the Duke generation level, shall be added to the EMC Monthly Demand Quantity determined in accordance with Section 7.1.4.1 or 7.2.4.1 as applicable or to the Monthly Billing Demand determined in accordance with Section 7.2.6.3.2 or Section 7.3.2.2 for such Month, as applicable; (ii) for purposes of calculating the electric energy charges under Sections 7.1.5, 7.2.5, 7.2.6.4 and 7.3.3, as applicable, the amount of electric energy provided to EMC by such PURPA Resource during an Hour, increased for losses between the point of measurement of EMC’s Native Load and the Duke generation level, shall be added to EMC’s Native Load and to the EMC Group Native Load for such Hour; and (iii) Duke shall credit EMC, on a Monthly basis, an amount equal to the electric capacity and energy credits to which EMC would be entitled as set forth in Duke’s retail electric tariff on file with the NCUC, Schedule PP-H or Schedule PP-N (as applicable), Interconnected to Distribution System or Transmission System (as applicable), or its successor tariff, if the capacity and electric energy provided to EMC by such PURPA Resource were provided to Duke pursuant to and in accordance with such schedules. The interconnection to Duke’s (rather than the EMC’s) Distribution System or Transmission System, as those terms are defined in the schedules, will determine whether the Distribution System or Transmission System rates apply. EMC will coordinate with Duke to

determine the proper application of these schedules. If Schedule PP-H or Schedule PP-N do not apply to the PURPA Resource, then Duke shall credit EMC, on a Monthly basis, an amount equal to the electric capacity and energy credits to which EMC would be entitled under PURPA if the electric capacity and electric energy provided to EMC by such PURPA Resource were provided to Duke pursuant to PURPA. EMC’s purchase of the electric capacity and energy from a PURPA Resource shall not affect the determination of the Annual Capacity Quantity determined in accordance with Sections 3.5.2.3.1, 3.5.2.3.2 or 3.5.2.3.3, as applicable.

Article 6

Priority of Service

6.1 Interruption of FFR Supplemental Service and Partial Requirements Service . FFR Supplemental Service and Partial Requirements Service shall have an interruption priority equivalent to Duke’s Native Load. It is expressly understood and agreed that, except for Duke’s failure to comply with Section 6.2 or as provided in Section 6.4, Duke shall not be liable to EMC for damages resulting from any such interruptions or impairment of FFR Supplemental Service or Partial Requirements Service. Duke shall use Commercially Reasonable Efforts to notify EMC by telephone of any scheduled interruption or scheduled impairment of service hereunder and shall use Commercially Reasonable Efforts to confirm such notice by facsimile, electronic mail, or letter on the same date such notice was given. Duke shall notify EMC by telephone of any unscheduled interruption or impairment of service hereunder as soon as reasonably practicable under the circumstances resulting in such unscheduled interruption or impairment of service. Duke shall use Commercially Reasonable Efforts to remove all causes of such interrupted or impaired service hereunder.

6.2 Curtailments of Load . Except as provided in Section 4.2.6, EMC’s Native Load shall be subject to curtailment only in accordance with this Section 6.2. In the event that Duke curtails Duke Native Load for any reason, including Force Majeure, EMC shall curtail its load as directed by Duke. Except as provided in Section 4.2.6, Duke shall not adversely distinguish against EMC’s Native Load in curtailing Duke’s Native Load and directing EMC to curtail EMC’s Native Load; provided, however, that Duke has sole responsibility to design all curtailments, and may order any manner of curtailment that Duke believes is appropriate so long as EMC’s Native Load and Duke’s Native Load present in the electrical area being curtailed are curtailed on a non-discriminatory basis. In permitting EMC to restore EMC’s Native Load and restoring Duke’s Native Load that was curtailed, Duke shall not adversely distinguish against EMC’s Native Load, except as provided in Section 4.2.6. The load curtailment and restoration provisions set forth in this Section 6.2 are in addition to, and without limitation of, the load curtailment and restoration provisions set forth in Section 4.2.6.

6.3 Emergency Load Curtailment Program . EMC agrees to implement an emergency load curtailment program for the curtailment of EMC’s Native Load in the event a load curtailment order is made by Duke. EMC shall comply with its obligation to implement and maintain an emergency load curtailment program and to curtail EMC’s Native Load in the manner specified by Section 6.2.

6.4 Substitute Energy . In the event that Duke fails to deliver a sufficient quantity of electric energy to meet its obligations to provide FFR Supplemental Service or Partial Requirements Service, as the case may be, and Duke’s failure to deliver such electric energy is not pursuant to a curtailment permitted under Section 4.2.6 or 6.2 of this Agreement, or is otherwise excused under this Agreement, Duke shall pay to EMC an amount equal to EMC’s Cover Costs, if any, incurred for the electric energy that EMC obtained to replace such electric energy (“Substitute Energy”) Duke failed to supply. EMC’s Cover Costs shall be equal to Substitute Energy Costs incurred by EMC for the Substitute Energy minus the costs that EMC would have incurred had Duke supplied the electric energy to EMC. EMC shall bill its Cover Costs to Duke in accordance with the provisions of Article 13. In the event that EMC incurs Cover Costs for Substitute Energy over a period that extends past the Month in which Duke’s failure to deliver electric energy occurs, then Duke shall pay the Cover Costs incurred in the following Month(s) in accordance with the billing and payment provisions of Article 13.

6.5 Substitute Energy Costs . Substitute Energy Costs shall be equal to (i) in the case in which EMC contracts with an energy supplier to provide Substitute Energy to EMC, the cost that EMC, acting in a commercially reasonable manner, incurs to purchase such Substitute Energy, or (ii) in the case in which Substitute Energy is provided to EMC by the Control Area operator, system operator, or similar entity providing such service on behalf of load (or load serving entities), the cost to EMC imposed on EMC by such Control Area operator, system operator, or other entity providing such Substitute Energy. In either case, Substitute Energy Costs shall include ancillary services charges, if any, reasonably incurred by EMC to the point where electric energy is delivered to the Transmission System or imposed to the point where electric energy is delivered to the Transmission System by the Control Area operator, system operator, or other entity providing Substitute Energy, including congestion charges, energy imbalance charges, backup capacity charges, replacement capacity charges, deficient capacity charges, commitment fees, ratcheted demand and similar charges incurred by EMC in obtaining such Substitute Energy.

Article 7

Capacity and Energy Charges

7.1 Charges During Commencement Date - December 31, 2006 .

7.1.1 General . For FFR Supplemental Service provided during the period beginning on the Commencement Date, and continuing through December 31, 2006, EMC shall pay to Duke the Monthly Demand Charge set forth in Section 7.1.4, the Duke Monthly Energy Charge set forth in Section 7.1.5.1, if applicable, the Monthly Scheduling Agent Service Charge set forth in Section 7.1.6 and, if applicable, the Monthly Reserve Capacity Charge set forth in Section 7.4, minus the EMC Monthly Energy Credit set forth in Section 7.1.5.5. In addition, the Duke Monthly Reconciliation Charge, Piedmont Monthly Reconciliation Credit, and the Monthly Inter-EMC Energy Transfer Reconciliation Charge shall be billed or credited as provided in Sections 7.1.5.11, 7.1.5.12, and 7.1.5.13. The charges set forth in this Section 7.1 are in addition to the other charges set forth in other sections of this Agreement.

7.1.2 [intentionally omitted].

7.1.3 [intentionally omitted].

7.1.4 Monthly Demand Charge . The Monthly Demand Charge for a Month shall be equal to the product of (i) the Monthly Demand Rate for the Year ($/kW-Month) and (ii) the Monthly Demand Amount for the Month (kW). The Monthly Demand Rate for 2006 shall be $0.75/kW-Month. The Monthly Demand Amount for a Month shall be equal to the product of (i) the EMC Monthly Demand Quantity for the Month divided by the EMC Group Combined Monthly Demand Quantity for the Month and (ii) the EMC Group Monthly Demand Quantity for the Month. In no event shall the Monthly Demand Quantity be less than zero. A sample calculation is provided in Attachment 7-2 .

7.1.4.1 EMC Monthly Demand Quantity . The EMC Monthly Demand Quantity for a Month shall be equal to the EMC Hourly Demand at the time of the Maximum Demand Hour for the Month minus EMC’s Base Obligation at the time of the Maximum Demand Hour. In no event shall the EMC Monthly Demand Quantity be less than zero.

7.1.4.2 EMC Group Combined Monthly Demand Quantity . The EMC Group Combined Monthly Demand Quantity for a Month shall be equal to the sum of (i) the EMC Monthly Demand Quantity for the Month as determined in Section 7.1.4.1 of this Agreement, (ii) the EMC Monthly Demand Quantity for the Month as determined in Section 7.1.4.1 of the Duke-Blue Ridge Agreement, and (iii) the EMC Monthly Demand Quantity for the Month as determined in Section 7.1.4.1 of the Duke-Rutherford Agreement.

7.1.4.3 EMC Group Monthly Demand Quantity . The EMC Group Monthly Demand Quantity for a Month shall be equal to the difference between the EMC Group Hourly Demand and the EMC Group’s Base Obligation during the Maximum Demand Hour of the Month, but in no event shall the EMC Group Monthly Demand Quantity for a Month be less than zero. The EMC Group Hourly Demand for an Hour shall be equal to the integrated sixty (60) minute demand of the EMC Group Native Load during the Hour. The Maximum Demand Hour of a Month shall be the Hour in which the positive difference between the EMC Group Native Load and the EMC Group’s Base Obligation is the greatest (as determined by subtracting the EMC Group’s Base Obligation from the EMC Group Native Load in every Hour of the Month, to determine the Hour in which such maximum difference for the Month occurs).

7.1.5 Monthly Energy Charges .

7.1.5.1 Duke Monthly Energy Charge . The Duke Monthly Energy Charge for a Month shall be equal to the sum of the Duke Hourly Energy Charges for the Month. The Duke Hourly Energy Charge for an Hour shall be equal to the sum of the Piedmont Allocated Share of the Duke Total Hourly Energy Charge for the Hour plus the Piedmont Allocated Share of the Inter-EMC Energy Charge for the Hour.

7.1.5.2 Duke Total Hourly Energy Charge . The Duke Total Hourly Energy Charge for an Hour shall be equal to the product of (i) one hundred thirteen percent (113%) of Duke’s Territorial Incremental Cost for the Hour and (ii) the EMC Group Energy Purchase Amount for the Hour. The amount of electric energy delivered by Duke to the EMC Group during any Hour shall be calculated as set forth in Section 7.1.5.10.

7.1.5.3 Piedmont Allocated Share of Duke Total Hourly Energy Charge . The Piedmont Allocated Share of the Duke Total Hourly Energy Charge for an Hour shall be calculated as set forth in Attachment 7-3 . An example showing the calculation of the Piedmont Allocated Share of the Duke Total Hourly Energy Charge for an Hour is shown in Attachment 7-4 .

7.1.5.4 Piedmont Allocated Share of Inter-EMC Energy Charge . The Piedmont Allocated Share of the Inter-EMC Energy Charge for an Hour shall be calculated as set forth in Attachment 7-3 . An example showing the calculation of the Piedmont Allocated Share of the Inter-EMC Energy Charge for an Hour is shown in Attachment 7-4 .

7.1.5.5 EMC Monthly Energy Credit . The EMC Monthly Energy Credit for a Month shall be equal to the sum of the EMC Hourly Energy Credits for the Month. The EMC Hourly Energy Credit for an Hour shall be equal to the sum of the Piedmont Allocated Share of the EMC Group Total Hourly Energy Credit for the Hour plus the Piedmont Allocated Share of the Inter-EMC Energy Credit for the Hour.

7.1.5.6 EMC Group Total Hourly Energy Credit . The EMC Group Total Hourly Energy Credit for an Hour shall be equal to the product of (i) ninety percent (90%) of Duke’s Territorial Decremental Cost for the Hour and (ii) the EMC Group Energy Credit Amount for the Hour. The amount of electric energy delivered by the EMC Group to Duke during any Hour shall be calculated as set forth in Section 7.1.5.10.

7.1.5.7 Piedmont Allocated Share of EMC Group Total Hourly Energy Credit . The Piedmont Allocated Share of the EMC Group Total Hourly Energy Credit for an Hour shall be calculated as set forth in Attachment 7-3 . An example showing the calculation of the Piedmont Allocated Share of the EMC Group Total Hourly Energy Credit for an Hour is shown in Attachment 7-4 .

7.1.5.8 Piedmont Allocated Share of Inter-EMC Energy Credit . The Piedmont Allocated Share of the Inter-EMC Energy Credit for an Hour shall be calculated as set forth in Attachment 7-3 . An example showing the calculation of the Piedmont Allocated Share of the Inter-EMC Energy Credit for an Hour is shown in Attachment 7-4 .

7.1.5.9 Calculation of Piedmont Hourly Energy Amounts . The amount of electric energy delivered by Duke to Piedmont, and by Piedmont to Duke for an Hour, shall be calculated as follows: electric energy scheduled under this Agreement shall be scheduled using two (2) dynamic (instantaneous) signals representing the difference between EMC’s Native Load and EMC’s Base Obligation. At the time of this Agreement, these signals are sampled once every four (4) seconds; the time period between each sample as defined herein shall be referred to as an “Interval”. The time duration of the Intervals shall be subject to change based on Duke’s standard operating practices. A signal during an Interval in which EMC’s Native Load exceeds EMC’s Base Obligation shall be referred to herein as an EMC Call Signal, indicating electric energy supplied by Duke to Piedmont. A signal during an Interval in which EMC’s Base Obligation exceeds EMC’s Native Load shall be referred to herein as an EMC Put Signal, indicating electric energy being supplied by Piedmont to Duke. The integrated value of the EMC Call Signals (separate from and not combined with the EMC Put Signals) summed

across all Intervals during the Hour shall be used as the amount of electric energy supplied by Duke to Piedmont for the Hour, and the integrated value of the EMC Put Signals (separate from and not combined with the EMC Call Signals) summed across all Intervals during the Hour shall be used as the amount of electric energy supplied by Piedmont to Duke for the Hour. The amount of electric energy supplied by Duke to Piedmont for the Hour, as calculated in this Section 7.1.5.9, shall be referred to herein as the Piedmont Energy Purchase Amount for the Hour. The amount of electric energy supplied by Piedmont to Duke for the Hour, as determined in this Section 7.1.5.9, shall be referred to herein as the Piedmont Energy Credit Amount for the Hour. An example showing the calculation of such amounts is shown in Attachment 7-5 .

7.1.5.10 Calculation of EMC Group Energy Amounts . The amount of electric energy delivered by Duke to the EMC Group, and by the EMC Group to Duke, for the Hour shall be calculated as follows: Electric energy scheduled under the Partial Requirements Agreements shall be scheduled using two (2) dynamic (instantaneous) signals representing the differences between the EMC Group Native Load and the EMC Group’s Base Obligation. At the time of this Agreement, these signals are sampled once every four (4) seconds; the time period between each sample as defined herein shall be referred to as an “Interval”. The time duration of the Intervals shall be subject to change based on Duke’s standard operating practices. A signal during an Interval in which EMC Group’s Native Load exceeds EMC Group’s Base Obligation shall be referred to herein as an EMC Group Call Signal, indicating electric energy supplied by Duke to the EMC Group. A signal during an Interval in which EMC Group’s Base Obligation exceeds EMC Group’s Native Load shall be referred to herein as an EMC Group Put Signal, indicating electric energy being supplied by EMC Group to Duke. The integrated value of the EMC Group Call Signals (separate from and not combined with the EMC Group Put Signals) summed across all Intervals during the Hour shall be used as the amount of electric energy supplied by Duke to the EMC Group for the Hour, and the integrated value of the EMC Group Put Signals (separate from and not combined with the EMC Group Call Signals) summed across all Intervals during the Hour shall be used as the amount of electric energy supplied by the EMC Group to Duke for the Hour. The amount of electric energy supplied by Duke to EMC Group for the Hour, as calculated in this Section 7.1.5.10, shall be referred to herein as EMC Group Energy Purchase Amount for the Hour. The amount of electric energy supplied by the EMC Group to Duke for the Hour, as determined in this Section 7.1.5.10, shall be referred to herein as the EMC Group Energy Credit Amount for the Hour. An example showing the calculation of such amounts is shown in Attachment 7-6 .

7.1.5.11 Duke Monthly Reconciliation Charge . The Duke Monthly Reconciliation Charge for a Month shall be equal to the sum of the Duke Hourly Reconciliation Charges for the Month. The Duke Hourly Reconciliation Charge for an Hour shall be equal to the product of (a) the Duke Total Hourly Energy Charge for the Hour minus the Duke Reconciliation Amount for the Hour and (b) the Reconciliation Allocation Factor. The Duke Reconciliation Amount for an Hour shall be equal to the sum of (i) the Piedmont Allocated Share of the Duke Total Hourly Energy Charge for the Hour as set forth in Section 7.1.5.3 of this Agreement, (ii) the Rutherford Allocated Share of the Duke Total Hourly Energy Charge for the Hour as set forth in Section 7.1.5.3 of the Duke-Rutherford Agreement, and (iii) the Blue Ridge Allocated Share of the Duke Total Hourly Energy Charge for the Hour as set forth in Section 7.1.5.3 of the Duke-Blue Ridge Agreement. If the Duke Monthly Reconciliation Charge is positive, EMC shall pay such amount to Duke; if the Duke Monthly Reconciliation Charge is negative, such amount shall be credited to EMC.

7.1.5.12 Piedmont Monthly Reconciliation Credit . The Piedmont Monthly Reconciliation Credit for a Month shall be equal to the sum of the Piedmont Hourly Reconciliation Credits for the Month. The Piedmont Hourly Reconciliation Credit for an Hour shall be equal to the product of (a) the EMC Group Total Hourly Energy Credit for the Hour minus the EMC Group Reconciliation Amount for the Hour and (b) the Reconciliation Allocation Factor. The EMC Group Reconciliation Amount for an Hour shall be equal to the sum of (i) the Piedmont Allocated Share of the EMC Group Total Hourly Energy Credit for the Hour as set forth in Section 7.1.5.7 of this Agreement, (ii) the Rutherford Allocated Share of the EMC Group Total Hourly Energy Credit for the Hour as set forth in Section 7.1.5.7 of the Duke-Rutherford Agreement, and (iii) the Blue Ridge Allocated Share of the EMC Group Total Hourly Energy Credit for the Hour as set forth in Section 7.1.5.7 of the Duke-Blue Ridge Agreement. If the Piedmont Monthly Reconciliation Credit is negative, EMC shall pay such amount to Duke; if the Piedmont Monthly Reconciliation Credit is positive, such amount shall be credited to EMC.

7.1.5.13 Inter-EMC Energy Transfer Reconciliation Charge . The Monthly Inter-EMC Energy Transfer Reconciliation Charge for a Month shall be equal to the sum of the Hourly Inter-EMC Transfer Reconciliation Charges for the Month. The Hourly Inter-EMC Transfer Reconciliation Charge for an Hour shall be equal to the product of (a) the Reconciliation Allocation Factor and (b) (i) the sum of the Piedmont Allocated Share of the Inter-EMC Energy Charge for the Hour as set forth in Section 7.1.5.4 of this Agreement, the Rutherford Allocated Share of the Inter-EMC Energy Charge for the Hour as set forth in Section 7.1.5.4 of the Duke-Rutherford Agreement, and the Blue Ridge Allocated Share of the Inter-EMC Energy Charge for the Hour as set forth in Section 7.1.5.4 of the Duke-Blue Ridge Agreement, minus (ii) the sum of the Piedmont Allocated Share of the Inter-EMC Energy Credit for the Hour as set forth in Section 7.1.5.8 of this Agreement, the Rutherford Allocated Share of the Inter-EMC Energy Credit for the Hour as set forth in Section 7.1.5.8 of the Duke-Rutherford Agreement, and the Blue Ridge Allocated Share of the Inter-EMC Energy Credit for the Hour as set forth in Section 7.1.5.8 of the Duke-Blue Ridge Agreement. If the Monthly Inter-EMC Energy Transfer Reconciliation Charge is negative, EMC shall pay such amount to Duke. If the Monthly Inter-EMC Energy Transfer Reconciliation Charge is positive, such amount shall be credited to EMC.

7.1.6 Scheduling Agent Service Charge . In the event that this Agreement is terminated in accordance with the provisions of Section 3.5.2.2, EMC shall pay to Duke the Monthly Scheduling Agent Service Charge commencing on the date that Scheduling Agent Services commence. The Monthly Scheduling Agent Service Charge for a Month shall be equal to one thousand dollars ($1,000) per Month.

Duke-Blue Ridge Agreement is in effect, before which time and after which time such quantities shall be deemed to be equal to zero; and (ii) all references in this Agreement to quantities under or as determined or set forth in the Duke-Rutherford Agreement shall be deemed to refer to such quantities during the period in which the Duke-Rutherford Agreement is in effect, before which time and after which time such quantities shall be deemed to be equal to zero. For example, if this Agreement and the Duke-Blue Ridge Agreement terminate August 31, 2008, and the Duke-Rutherford Agreement terminates August 31, 2007, then during the period through August 31, 2007, EMC Group Native Load shall mean the sum of (i) the EMC Native Load under this Agreement, (ii) the EMC Native Load under the Duke-Blue Ridge Agreement, and (iii) the EMC Native Load under the Duke-Rutherford Agreement, and during the period September 1, 2007 through August 31, 2008, EMC Group Native Load shall mean the sum of (i) the EMC Native Load under this Agreement and (ii) the EMC Native Load under the Duke-Blue Ridge Agreement. In addition, for purposes of calculating the charges under Sections 3.5.2.3 and 7.1 (including charges and credits calculated pursuant to Section 7.1 in the event that EMC exercises its option pursuant to Section 3.5.2.3), all references to “EMC Group” shall refer collectively to the members of such group that are served under those of the above-referenced Agreements that are then in effect ( e.g. , in the above example, “EMC Group” would no longer include Rutherford effective September 1, 2007).

7.2 Charges During January 1, 2007 – December 31, 2010 .

7.2.1 For FFR Supplemental Service provided during the period beginning on January 1, 2007, and continuing through December 31, 2010, EMC shall pay to Duke the Base Annual Capacity Charge set forth in Section 7.2.2, the Excess Annual Capacity Charge set forth in Section 7.2.3, the Monthly Demand Charge set forth in Section 7.2.4, the Duke Monthly Energy Charge set forth in Section 7.2.5.1, and, if applicable, the Monthly Reserve Capacity Charge set forth in Section 7.4, minus the EMC Monthly Energy Credit set forth in Section 7.2.5.3. The charges set forth in this Section 7.2 are in addition to the other charges set forth in other sections of this Agreement.

7.2.2 Base Annual Capacity Charge . The Base Annual Capacity Charge for a Year shall be equal to the product of (i) the Annual Capacity Price for the Year ($/kW-Year) and (ii) the Annual Capacity Quantity for the Year (kW). The Annual Capacity Price for 2007 through 2010 shall be as follows:

2007 $38.00/kW-year

2008 $40.00 kW-year

2009 $57.00 kW-year

2010 $58.00 kW-year

and the Annual Capacity Quantity for 2007 through 2010 shall be as follows:

2007 23,000 kW

2008 24,000 kW

2009 23,000 kW

2010 24,000 kW

Provided, that the Annual Capacity Quantity amounts set forth in this Secton 7.2.2 for 2009 and 2010 shall be decreased, on a kW for kW basis, for any increase in EMC’s Base Obligation that occurs pursuant to Section 5.1.4. The Base Annual Capacity Charge shall be billed in accordance with Article 13 in the July statement each Year.

7.2.3 Excess Annual Capacity Charge . The Excess Annual Capacity Charge for a Year shall be equal to the product of (i) the Excess Annual Capacity Price for the Year ($/kW-Year) and (ii) the EMC Excess Annual Capacity Quantity for the Year (kW). The Excess Annual Capacity Charge for the Year shall be billed in accordance with Article 13 in the September statement based on the actual Duke billing data during July and August of such Year.

7.2.3.1 Excess Annual Capacity Price . The Excess Annual Capacity Price for each Year shall be equal to 120 percent of the Annual Capacity Price for that Year as identified in Section 7.2.2.

7.2.3.2 EMC Excess Annual Capacity Quantity . The EMC Excess Annual Capacity Quantity for a Year shall be equal to the EMC Coincident Peak Demand for the Year minus EMC’s Base Obligation for the Hour in such Year in which the EMC Coincident Peak Demand occurs, minus the Annual Capacity Quantity for the Year. In no event shall the EMC Excess Annual Capacity Quantity be less than zero. The EMC Coincident Peak Demand for a Year shall be equal to the EMC Hourly Demand that is coincident with the maximum integrated sixty (60) minute Duke Schedule 1 Demands during July and August of the Year. The EMC Hourly Demand for an Hour shall be equal to the integrated sixty (60) minute demand of EMC’s Native Load during the Hour.

7.2.4 Monthly Demand Charge . The Monthly Demand Charge for a Month shall be equal to the product of (i) the Monthly Demand Rate for the Year ($/kW-Month) and (ii) the EMC Monthly Demand Quantity for the Month (kW). The Monthly Demand Rate for 2007 through 2010 shall be as follows:

2007 $1.08/kW-month

2008 $1.25 kW-month

2009 $1.33 kW-month

2010 $1.42 kW-month

7.2.4.1 EMC Monthly Demand Quantity . The EMC Monthly Demand Quantity for a Month shall be equal to the EMC Hourly Demand at the time of the Maximum Demand Hour for the Month minus EMC’s Base Obligation at the time of the Maximum Demand Hour. In no event shall the EMC Monthly Demand Quantity be less than zero. The Maximum Demand Hour of a Month shall be the Hour in which the positive difference between EMC’s Native Load and EMC’s Base Obligation is the greatest (as determined by subtracting EMC’s Base Obligation from EMC’s Native Load in every Hour of the Month, to determine the Hour in which such maximum difference for the Month occurs).

7.2.5 Monthly Energy Charges .

7.2.5.1 Duke Monthly Energy Charge . The Duke Monthly Energy Charge for a Month shall be equal to the sum of the Duke Hourly Energy Charges for the Month.

7.2.5.2 Duke Hourly Energy Charge . The Duke Hourly Energy Charge for an Hour shall be equal to the product of (i) one hundred thirteen percent (113%) of Duke’s Territorial Incremental Cost for the Hour and (ii) the Piedmont Energy Purchase Amount for the Hour. The amount of electric energy delivered by Duke to EMC during any Hour shall be calculated as set forth in Section 7.2.5.5.

7.2.5.3 EMC Monthly Energy Credit . The EMC Monthly Energy Credit for a Month shall be equal to the sum of the EMC Hourly Energy Credits for the Month.

7.2.5.4 EMC Hourly Energy Credit . The EMC Hourly Energy Credit for an Hour shall be equal to the product of (i) ninety percent (90%) of Duke’s Territorial Decremental Cost for the Hour and (ii) the Piedmont Energy Credit Amount for the Hour. The amount of electric energy delivered by the EMC to Duke during any Hour shall be calculated as set forth in Section 7.2.5.5.

7.2.5.5 Calculation of Piedmont Hourly Energy Amounts . The amount of electric energy delivered by Duke to Piedmont, and by Piedmont to Duke for an Hour, shall be calculated as follows: electric energy scheduled under this Agreement shall be scheduled using two (2) dynamic (instantaneous) signals representing the difference between EMC’s Native Load and EMC’s Base Obligation. At the time of this Agreement, these signals are sampled once every four (4) seconds; the time period between each sample as defined herein shall be referred to as an “Interval”. The time duration of the Intervals shall be subject to change based on Duke’s standard operating practices. A signal during an Interval in which EMC’s Native Load exceeds EMC’s Base Obligation shall be referred to herein as an EMC Call Signal, indicating electric energy supplied by Duke to Piedmont. A signal during an Interval in which EMC’s Base Obligation exceeds EMC’s Native Load shall be referred to herein as an EMC Put Signal, indicating electric energy being supplied by Piedmont to Duke. The integrated value of the EMC Call Signals (separate from and not combined with the EMC Put Signals) summed across all Intervals during the Hour shall be used as the amount of energy supplied by Duke to Piedmont for the Hour, and the integrated value of the EMC Put Signals (separate from and not combined with the EMC Call Signals) summed across all Intervals during the Hour shall be used as the amount of energy supplied by Piedmont to Duke for the Hour. The amount of electric energy supplied by Duke to Piedmont for the Hour, as calculated in this Section 7.2.5.5, shall be referred to herein as the Piedmont Energy Purchase Amount for the Hour. The amount of electric energy supplied by Piedmont to Duke for the Hour, as determined in this Section 7.2.5.5, shall be referred to herein as the Piedmont Energy Credit Amount for the Hour. An example showing the calculation of such amounts is shown in Attachment 7-5 .

7.2.6 System Average Pricing Option

7.2.6.1 Exercise of Option . During the period January 1, 2007 through December 31, 2010, EMC shall have the option of being subject to the pricing provisions set forth in Sections 7.2.6.2, 7.2.6.3, and 7.2.6.4 in lieu of the pricing provisions set forth in Sections 7.2.1, 7.2.2, 7.2.3, 7.2.4 and 7.2.5. EMC may exercise such option (referred to herein as the “System Average Pricing Option”) for the period beginning January 1, 2007, January 1, 2008, January 1, 2009, or January 1, 2010, and ending December 31, 2010. The period that EMC selects pursuant to this option (i.e., January 1, 2007 - December 31, 2010, January 1, 2008 - December 31, 2010, January 1, 2009 - December 31, 2010, or January 1, 2010 - December 31, 2010) shall be referred to herein as the “System Average Pricing Option Period.” EMC may exercise such option by giving notice (such notice referred to herein as the “System Average Pricing Option Notice”) to Duke no later than September 30 of the Year prior to the Year in which the System Average Pricing Option Period that EMC selects would commence. For example, if EMC wishes to exercise its option under this Section 7.2.6 effective January 1, 2008, it must provide its System Average Pricing Option Notice no later than September 30, 2007. The System Average Pricing Option Notice is effective when it is deemed given in accordance with Section 16.22. Once the System Average Pricing Option Notice is given to Duke, it shall not be amended, modified or otherwise revoked for any reasons unless such amendment, modification or revocation is mutually agreed to by both Parties in writing.

7.2.6.2 General . During the System Average Price Option Period, EMC shall pay to Duke the Monthly Demand Charge set forth in Section 7.2.6.3 and the Duke Monthly Energy Charge set forth in Section 7.2.6.4, in lieu of the charges set forth in Sections 7.2.1, 7.2.2, 7.2.3, 7.2.4, and 7.2.5. The charges set forth in Section 7.2.6 are in addition to the other charges set forth in other sections of this Agreement (including, if applicable, the Monthly Reserve Capacity Charge set forth in Section 7.4).

7.2.6.3 Monthly Demand Charge . The Monthly Demand Charge for a Month shall be equal to the product of (i) the Monthly Billing Demand for the Month (kW) and (ii) the Monthly Demand Rate for the Year ($/kW-Month).

7.2.6.3.1 Monthly Demand Rate . The Monthly Demand Rate for each Year shall be calculated in accordance with the formula rate set forth in Schedule 1 . The Monthly Demand Rate initially shall be calculated based on estimated data, and shall be subject to true-up after actual data become available. The true-up shall be provided to EMC no later than June 30 following the Year in which service was provided, and shall include interest on any refunds or surcharges calculated in accordance with Section 35.19a of FERC’s regulations.

7.2.6.3.2 Monthly Billing Demand . The Monthly Billing Demand for each Month of the Year shall be equal to the average of the twenty (20) EMC Peak Hour Billing Demands coincident with the twenty (20) highest Hourly (integrated sixty-minute) Duke Schedule 1 Demands during July and August of such Year. The EMC Peak Hour Billing Demand for an Hour shall be equal to the integrated sixty (60) minute EMC Native Load demand (kW) for the Hour minus EMC’s Base Obligation (kW) for such Hour, but in no event shall the EMC Peak Hour billing Demand for an Hour (or the Monthly Billing Demand) be less than zero. The Monthly Billing Demand initially shall be calculated based on estimated data, and shall be

subject to true-up after actual data become available. The true-up shall be provided to EMC no later than June 30 following the Year in which service was provided, and shall include interest on any refunds or surcharges calculated in accordance with Section 35.19a of FERC’s regulations. An example showing the calculation of this billing demand is shown in Attachment 7-7 .

7.2.6.4. Monthly Energy Charge . The Duke Monthly Energy Charge for a Month shall be equal to the sum of the Monthly Fuel Charge and Monthly Variable O&M Charge for the Month. If the Duke Monthly Energy Charge is positive, EMC shall pay such amount to Duke. If the Duke Monthly Energy Charge is negative, Duke shall credit such amount to EMC.

7.2.6.4.1 Monthly Fuel Charge . The Monthly Fuel Charge for a Month shall be equal to the sum of the Hourly Fuel Charges for the Month. The Hourly Fuel Charge for an Hour shall be equal to the product (i) EMC’s Native Load demands during the Hour (kW) minus EMC’s Base Obligation for the Hour (kW) and (ii) the Fuel Rate for the Year ($/kWh). The Fuel Rate for each Year shall be calculated in accordance with the formula rate set forth in Schedule 1 . The Fuel Rate shall initially be calculated based on estimated data, and shall be subject to true-up after actual data become available. The true-up shall be provided to EMC no later than June 30 following the Year in which service was provided, and shall include interest on any refunds or surcharges calculated in accordance with Section 35.19a of FERC’s regulations. Duke will keep EMC informed of the true-up subtotal on a semi-annual basis during a Year.

7.2.6.4.2 Monthly Variable O&M Charge . The Monthly Variable O&M Charge for a Month shall be equal to the sum of the Hourly Variable O&M Charges for the Month. The Hourly Variable O&M Charge for an Hour shall be equal to the product of (i) EMC’s Native Load demands during the Hour (kW) minus EMC’s Base Obligation for the Hour (kW), and (ii) the Variable O&M Rate for the Year ($/kWh). The Variable O&M Rate for each Year shall be calculated in accordance with the formula rate set forth in Schedule 1 . The Variable O&M Rate initially shall be calculated based on estimated data, and shall be subject to true-up after actual data become available. The true-up shall be provided to EMC no later than June 30 following the Year in which service was provided, and shall include interest on any refunds or surcharges calculated in accordance with Section 35.19a of FERC’s regulations.

7.3 Charges Commencing January 1, 2011 .

7.3.1 General . For service provided commencing January 1, 2011 through the termination of this Agreement, EMC shall pay to Duke the Monthly Demand Charge set forth in Section 7.3.2 and the Duke Monthly Energy Charge set forth in Section 7.3.3. The charges set forth in this Section 7.3 are in addition to the other charges set forth in other sections of this Agreement.

7.3.2 Monthly Demand Charge . The Monthly Demand Charge for a Month shall be equal to the product of (i) the Monthly Billing Demand for the Month (kW) and (ii) the Monthly Demand Rate for the Year ($/kW-Month).

7.3.2.1 Monthly Demand Rate . The Monthly Demand Rate for each Year shall be calculated in accordance with the formula rate set forth in Schedule 1 . The Monthly Demand Rate shall initially be calculated based on estimated data, and shall be subject to true-up after actual data become available. The true-up shall be provided to EMC no later than June 30 following the Year in which service was provided, and shall include interest on any refunds or surcharges calculated in accordance with Section 35.19a of FERC’s regulations.

7.3.2.2 Monthly Billing Demand . The Monthly Billing Demand for each month of a Year shall be equal to the average of the twenty (20) EMC Peak Hour Billing Demands coincident with the twenty (20) highest Hourly (integrated sixty-minute) Duke Schedule 1 Demands during the Annual Planning Period for such Year (as determined in Section 7.3.2.3). The EMC Peak Hour Billing Demand for an Hour shall be equal to the integrated sixty (60) minute EMC Native Load demand (kW) for the Hour minus the Partial Requirements Resources (kW) for such Hour, but in no event shall the EMC Peak Hour Billing Demand (or the Monthly Billing Demand) be less than zero. The Monthly Billing Demand shall initially be calculated based on estimated data, and shall be subject to true-up after actual data become available. The true-up shall be provided to EMC no later than June 30 following the Year in which service was provided, and shall include interest on any refunds or surcharges calculated in accordance with Section 35.19a of FERC’s regulations. Examples showing the calculation of the Monthly Billing Demand are shown in Attachment 7-8 .

7.3.2.3 Determination of Annual Planning Period . If the then-effective Annual Planning Period is the Summer Period, the Annual Planning Period for purposes of determining the Monthly Billing Demand for the Year under Section 7.3.2.2 shall be the Summer Period that occurs within such Year (for example, if the Annual Planning Period in 2012 is the Summer Period, and the Summer Period is May - September, the Annual Planning Period for purposes of determining the Monthly Billing Demand for 2012 under Section 7.3.2.2 is May 2012 - September 2012). If the then-effective Annual Planning Period is the Winter Period, the Annual Planning Period for purposes of determining the Monthly Billing Demand for the Year under Section 7.3.2.2 shall be the Winter Period that ends in such Year (for example, if the Annual Planning Period in 2012 is the Winter Period, and the Winter Period is October - April, the Annual Planning Period for purposes of determining the Monthly Billing Demand for 2012 under Section 7.3.2.2 is October 2011 - April 2012).

7.3.2.4 Annual Percentage . No later than June 30, 2012, and each June 30 thereafter during the Term, Duke shall calculate the Annual Percentage for the immediately preceding Year using the formula set forth in Attachment 7-9 , and shall provide such calculation to EMC, together with supporting information. The Annual Percentage may be a positive or negative value. In the event that the Annual Percentage for such Year is greater than positive four percent (4%), the Monthly Demand Rate for such Year calculated pursuant to Section 7.3.2.1 shall be reduced by the percentage equal to the Demand Rate Adjustment Percentage. This reduction shall only apply to the Year for which it is calculated. This reduction shall be reflected in the true-up provided to EMC pursuant to Section 7.3.2.1. In the event that the Annual Percentage for such Year is a positive four percent (4%) or less, or is negative, there shall be no adjustments to the Monthly Demand Rate under this Section 7.3.2.4 for such Year. Illustrative examples showing the calculation of the Annual Percentage and Demand Rate Adjustment Percentage and the resulting reduction, if any, to the Monthly Demand Rate are set forth in Attachment 7-10 .

7.3.3 Monthly Energy Charge . The Duke Monthly Energy Charge for a Month shall be equal to the sum of the Monthly Fuel Charge and Monthly Variable O&M Charge for the Month.

7.3.3.1 Monthly Fuel Charge . The Monthly Fuel Charge for a Month shall be equal to the sum of the Hourly Fuel Charges for the Month. The Hourly Fuel Charge for an Hour shall be equal to the product (i) EMC’s Native Load demand during the Hour (kW) minus the sum of (a) EMC’s Dispatched Baseload Resources for the Hour (kW) and (b) EMC’s Dispatched Combined Cycle Resources for the Hour for which EMC bears the Energy Cost pursuant to Section 4.3.3.1 (kW), and (ii) the Fuel Rate for the Year ($/kWh). The Fuel Rate for each Year shall be calculated in accordance with the formula rate set forth in Schedule 1 . The Fuel Rate shall initially be calculated based on estimated data, and shall be subject to true-up after actual data become available. The true-up shall be provided to EMC no later than June 30 following the Year in which service was provided, and shall include interest on any refunds or surcharges calculated in accordance with Section 35.19a of FERC’s regulations. Duke will keep EMC informed of the true-up subtotal on a semi-annual basis during a Year.

7.3.3.2 Monthly Variable O&M Charge . The Monthly Variable O&M Charge for a Month shall be equal to the sum of the Hourly Variable O&M Charges for the Month. The Hourly Variable O&M Charge for an Hour shall be equal to the product of (i) EMC’s Native Load demands during the Hour (kW) minus the sum of (a) EMC’s Dispatched Baseload Resources for the Hour (kW) and (b) EMC’s Dispatched Combined Cycle Resources for the Hour for which EMC bears the Energy Cost pursuant to Section 4.3.3.1 (kW) and (ii) the Variable O&M Rate for the Year ($/kWh). The Variable O&M Rate for each Year shall be calculated in accordance with the formula rate set forth in Schedule 1 . The Variable O&M Rate shall initially be calculated based on estimated data, and shall be subject to true-up after actual data become available. The true-up shall be provided to EMC no later than June 30 following the Year in which service was provided, and shall include interest on any refunds or surcharges calculated in accordance with Section 35.19a of FERC’s regulations.

7.4 Monthly Reserve Capacity Charges . In the event that Duke provides Replacement Energy to EMC pursuant to Section 4.2.4 in an amount of five thousand (5,000) kW or greater during any Hour of a Year, EMC shall pay a Monthly Reserve Capacity Charge equal to the product of (i) the Monthly Demand Rate as calculated in Section 7.3.2.1 and (ii) the amount (in kW) of reserves that would be required under Duke’s Generation Planning Practices for a generating resource of a size equivalent to the amount of Replacement Energy provided to EMC (the “Reserve Capacity Amount”). This charge shall commence on the Day following the Day on which Duke provided Replacement Energy to EMC, and shall terminate on December 31 of that Year. For example, if Duke provides a maximum amount of 100,000 kWh of Replacement Energy to EMC in any given Hour on July 15, 2007, and the reserves that would be required for a 100,000 kW generating resource under Duke’s Generation Planning Practices is 17,000 kW, EMC shall be responsible for a Monthly Reserve Capacity Charge for 17,000 kW from July 16, 2007, through December 31, 2007, subject to increase as provided in the next sentence. In the event that Duke provides Replacement Energy to EMC for any additional Hours during such Year, and the amount of Replacement Energy provided during any such Hours is greater than

that previously provided during the Year, then the Reserve Capacity Amount shall be increased to reflect such greater amount of Replacement Energy, effective the Day after the Replacement Energy is provided. In the event that Duke provides Replacement Energy to EMC in a subsequent Year, the foregoing provisions shall apply, and EMC shall pay Monthly Reserve Capacity Charges with respect to such Replacement Energy as provided above. Notwithstanding anything in this Section 7.4 to the contrary, the Monthly Reserve Capacity Charges shall terminate no later than December 31, 2010. Any Monthly Reserve Capacity Charge, or increase in such charge, that begins on a Day other than the first Day of the Month shall be adjusted pro rata for that Month to reflect the number of Days during the Month in which the charge or charge increase was in effect.

7.4.1 Force Majeure Events . Notwithstanding the provisions of Section 7.4, in the event that Duke provides Replacement Energy to EMC due to the occurrence of a force majeure event, EMC shall not incur a Monthly Reserve Capacity Charge due to Duke’s provision of Replacement Energy for the first twenty-four (24) Hours following such occurrence. For purposes of this Section 7.4.1, the term “force majeure” means an event or circumstance that: (i) prevents the party claiming to be affected by it from performing its obligations in whole or in part; (ii) is not within the reasonable control of the claiming party, or the result of the negligence of the claiming party, and (iii) by the exercise of due diligence, the claiming party is unable to overcome in a commercially reasonable manner, and, without limiting the scope of the definition, includes acts of God, or the public enemy, or insurrection, riot, acts of terrorism, civil disturbance or disorder, strikes, fire, earthquakes, floods, storms or other natural disasters, or actions or restraints by court order or governmental authority or arbitration award (so long as the claiming party has not sought or has opposed, to the extent reasonable, such actions or restraints). It is expressly acknowledged that transmission service interruptions or curtailments imposed by a transmission provider in response to transmission capacity or availability shortages shall not be “force majeure” events or circumstances for purposes of this Section 7.4.1.

7.5 Payment . All charges or payments contemplated by this Article 7 shall be made in accordance with provisions of Article 13.

7.6 Determination of EMC Capacity and Energy Demands . For purposes of determining the electric capacity and energy charges under this Agreement, EMC’s Native Load demands shall be as determined under the NOA (which demands shall include the adjustments under the NOA for losses between the point of delivery under the NITSA and the point of measurement, and the corrections under the NOA for any metering failures or inaccuracies), and shall be increased by (1 / (1 - TLF ), in order to reflect such demands at the generation level ( i.e. , at the point at which power is available for transmission). Metered receipts used in billings and accounting hereunder will in all cases include adjustments for such losses. TLF shall be equal to the transmission loss factor set forth in the Transmission Provider’s OATT, and shall be expressed as a decimal. For example, if the transmission loss factor in the Transmission Provider’s OATT is three percent (3%), then ( 1 / (1 - TLF )) shall be equal to ( 1 / (1 -.03)), or ( 1 / .97 ). In the event that the NOA is terminated, or the electric capacity and energy demands measured under the NOA no longer include an adjustment for losses between the point of delivery under the NITSA and the point of measurement or provisions for correcting such demands for metering failures or inaccuracies, then, for purposes of determining the capacity and energy charges under this Agreement, EMC’s metered electric capacity and energy demands shall be adjusted for losses

between the point of delivery under the NITSA and point of measurement and further increased by ( 1 / (1-TLF)), in order to reflect such demands at the generation level ( i.e. , at the point at which power is available for transmission), and suitable arrangements shall be made by the Parties for correcting such demands due to metering failures or inaccuracies.

Article 8

Scheduling Agent Services

8.1 Appointment of Duke as Scheduling Agent . EMC hereby appoints Duke as Scheduling Agent, effective on the Effective Date (or such earlier date as is required so that Scheduling Agent may begin rendering Scheduling Agent Services by the Commencement Date), as agent for EMC for the Term, for the limited purposes set forth in this Agreement, with full power and authority to render the Scheduling Agent Services, and Duke accepts such appointment.

8.1.1 Costs . The Parties acknowledge and agree that all costs and expenses incurred by Duke to provide Scheduling Agent Services are included in the charges set forth in Article 7 and, except as provided for in Section 7.1.6, EMC shall not be charged any additional rates, charges or fees in connection with Duke’s provision of Scheduling Agent Services.

8.2 Scheduling Policies . In providing Scheduling Agent Services hereunder, Duke shall comply with (i) the NCEMC policies set forth in Attachment 8-1 (“NCEMC Policies”) and (ii) the Transmission Provider’s OATT. To avoid uncertainty, for purposes of Section 8 of Attachment 8-1 (Part I of II), Piedmont’s “SEPA allocation” shall be zero.

8.3 Protocols . In advance of the Commencement Date, and from time to time thereafter as the Operating Committee may determine appropriate, the Operating Committee shall meet and make reasonable efforts to establish written protocols and procedures to implement the Scheduling Agent Services provided for hereunder, which shall be reviewed and agreed to by the Parties; provided however, that the Operating Committee’s failure to agree upon such protocols and procedures shall not affect in any way the Parties’ respective rights and obligations under this Article 8.

8.4 Scheduling Agent Services (Commencement Date through December 31, 2010) . Beginning on the Commencement Date and continuing through December 31, 2010, Duke shall provide the following Scheduling Agent Services:

8.4.1 Duke shall develop next-Day and multi-Day forecasts of EMC’s Native Load.

8.4.2 Duke shall provide NCEMC with seven-Day and next-Day forecasts of EMC’s Native Load.

8.4.3 Duke shall receive each Day the Nominations from MSCG, and confirm such Nominations with MSCG in writing, facsimile, e-mail, or any other agreed-upon form of communication.

8.4.4 Duke shall provide to NCEMC the Nominations that Duke receives pursuant to Section 8.4.3.

8.4.5 Duke shall provide operational forecasts of EMC Native Load as may be requested by the Transmission Provider from time to time.

8.4.6 [intentionally omitted]

8.4.7 [intentionally imitted]

8.4.8 Duke shall receive any information or notices from NCEMC or MSCG relating to any changes in the schedules of electric energy to be delivered to serve EMC’s Native Load.

8.4.9 Duke shall provide daily and Monthly reconciliation and checkout services to EMC with respect to each of NCEMC, the Transmission Provider, and MSCG in connection with services provided by such entities to serve EMC’s Native Load.

8.4.10 Duke shall reasonably cooperate with EMC to enable EMC to address issues that may arise in connection with invoices or bills rendered to EMC by the Transmission Provider in connection with the delivery of electric energy under the PPA, the WPSA, or EMC Contract Resources described in Sections 5.1.3, 5.1.4 and 5.1.5 to serve EMC’s Native Load. Such cooperation shall include providing EMC with data, records, and other information available to Duke and related to the invoices or bills at issue.

8.4.11 If Duke has information that MSCG was not informed of any transmission constraints or other impediments to deliveries under the PPA to the delivery points designated by MSCG, Duke shall, as promptly as reasonably practical, inform MSCG of any transmission constraints or other impediments to deliveries under the PPA to the delivery points designated by MSCG.

8.4.12 Duke shall serve as EMC’s Purchasing – Selling Entity.

8.4.13 Duke shall schedule to the Transmission Provider electric energy to be delivered from the EMC Contract Resources described in Sections 5.1.3, 5.1.4 and 5.1.5.

8.5 Scheduling Agent Services (January 1, 2011 through Termination) . Beginning on January 1, 2011, and continuing through the date of termination of this Agreement, Duke shall provide the following Scheduling Agent Services:

8.5.1 Duke shall develop next-Day and multi-Day forecasts of EMC’s Native Load.

8.5.2 Duke shall provide NCEMC with seven-Day and next-Day forecasts of EMC’s Native Load.

8.5.3 Duke shall provide to NCEMC with the daily schedule of electric energy to be made available each Hour to serve EMC’s Native Load under the WPSA.

8.5.4 [intentionally omitted]

8.5.5 [intentionally omitted]

8.5.6 Duke shall provide operational forecasts of EMC Native Load as may be requested by the Transmission Provider from time to time.

8.5.7 Duke shall receive any information or notices from NCEMC relating to any changes in the schedules of electric energy to be delivered to serve EMC’s Native Load.

8.5.8 Duke shall provide daily and Monthly reconciliation and checkout services to EMC with respect to NCEMC and the Transmission Provider in connection with services provided by those entities to serve EMC’s Native Load.

8.5.9 Duke shall reasonably cooperate with EMC to enable EMC to address issues that may arise in connection with invoices or bills rendered to EMC by the Transmission Provider in connection with the delivery of electric energy under the WPSA or EMC Contract Resources described in Section 5.2 to serve EMC’s Native Load. Such cooperation shall include, but is not limited to, providing EMC with data, records and other information available to Duke and related to the invoices or bills at issue.

8.5.10 Duke shall serve as EMC’s Purchasing – Selling Entity.

8.5.11 Duke shall schedule to the Transmission Provider electric energy to be delivered from the EMC Contract Resources described in Section 5.2.

8.6 New EMC Resources . If EMC obtains one or more new EMC Contract Resources in accordance with the provisions of Article 5 of this Agreement, the Parties shall negotiate appropriate revisions to this Agreement or the protocols and procedures developed under Section 8.3 as necessary for Duke to provide Scheduling Agent Services hereunder in connection with such new EMC Contract Resources; provided however, the failure of the Parties to agree on revisions to this Agreement or the protocols and procedures developed under Section 8.3 shall not relieve Duke of its obligation to schedule such new EMC Contract Resources.

8.7 Errors in Schedules . If Duke is notified by the Transmission Provider, NCEMC or a third party with respect to EMC Contract Resources described in Sections 5.1.3, 5.1.4, 5.1.5 or 5.2, that any schedule provided by Duke as Scheduling Agent has been rejected, Duke shall provide to the Transmission Provider, NCEMC or third party, as applicable, a substitute schedule for the Day in question taking into account the information provided by the Transmission Provider, NCEMC or third party, as applicable, in connection with such rejection.

8.8 EMC Responsibilities . In connection with Duke’s undertaking Scheduling Agent Services, EMC shall have the following obligations:

8.8.1 EMC shall provide Duke, as Scheduling Agent, with: (a) meter data such that Duke may calculate aggregate load in discrete locations or in aggregate load areas as determined by Transmission Provider; (b) five (5) years of the most recent historical load data; and (c) the Power Requirements Study (or such successor document) that EMC submits annually to the RUS.

8.8.2 EMC shall make arrangements with NCEMC, the Transmission Provider, and any third party responsible for providing for deliveries of new EMC Resources as provided for in Section 8.6, as are necessary for those parties to communicate with, and accept or receive schedules or other information submitted by or to Duke as Scheduling Agent.

8.8.3 During the period from the Commencement Date through December 31, 2010, EMC shall direct MSCG to communicate with, and provide Nominations to Duke as Scheduling Agent.

8.8.4 EMC shall reasonably cooperate with Duke as necessary for Duke to assist EMC in addressing issues that may arise in connection with invoices or bills rendered to EMC by the Transmission Provider, as provided for in Sections 8.4.10 and 8.5.9.

8.9 Duke’s Liability . Duke shall be liable for any damages arising from Duke’s unexcused failure to comply with the provisions of this Article 8.

8.10 Termination Assistance Service . Commencing six (6) Months prior to the scheduled termination of this Agreement and continuing through the termination date of this Agreement (the “Termination Assistance Period”), Duke shall provide to EMC, or at EMC’s request to EMC’s designee, such reasonable cooperation, assistance and service to cause the orderly and timely transition and migration of Scheduling Agent Services provided under this Agreement to EMC’s new energy supplier and/or scheduling agent without interruption or adverse effect (“Termination Assistance Service”). EMC may shorten or terminate the Termination Assistance Period by providing written notice to Duke.

Article 9

Transmission and Ancillary Services

9.1 Delivery Obligations . Duke shall be responsible for making all arrangements necessary and paying for all costs incurred under contractual arrangements necessary to deliver the electric energy provided hereunder to the Delivery Points. EMC shall be responsible for making and paying for all contractual arrangements necessary for the delivery of the electric energy provided hereunder from the Delivery Points.

9.2 Transmission Arrangements . This Agreement does not obligate Duke to provide any Transmission Service or Ancillary Services, and does not confer upon EMC any rights to service over the Transmission System. EMC shall be responsible for making separate contractual arrangements with the Transmission Provider for all Transmission Service and Ancillary Services to be provided to EMC.

9.3 Ancillary Services . Duke shall make Commercially Reasonable Efforts to assist in any effort by EMC to have the Transmission Provider recognize that the electric capacity and energy provided hereunder satisfies one or more of such Transmission Provider’s Ancillary Services requirements; provided, however, that nothing in this Section 9.3 shall in any way obligate Duke to provide, make arrangements for, or pay for any Ancillary Services except as expressly provided for in Section 9.3.1.

9.3.1 Energy Imbalance Responsibility . Duke shall reimburse EMC in accordance with the provisions of Article 13 for any Hour in which, as a result of Duke’s unexcused failure to

comply with the provisions of Article 8, Energy Imbalance Service charges are incurred by EMC in accordance with the Transmission Provider’s OATT. EMC shall reimburse Duke in accordance with the provisions of Article 13 for any Hour in which, as a result of Duke’s unexcused failure to comply with the provisions of Article 8, Energy Imbalance Service compensation is provided to EMC in accordance with the Transmission Provider’s OATT.

9.4 Regional Transmission Organization . If an ISO, RTO, ITC or other future organization, agency or authority that has been approved by FERC to serve as the Transmission Provider, then Duke and EMC will reasonably cooperate to make or enter into arrangements with such entity to assist such entity with the implementation of this Agreement. It is expressly understood that neither the implementation of an ISO, RTO, ITC or other future organization, agency or authority that has been approved by FERC to serve as the Transmission Provider nor the failure of the Parties to enter into the arrangements contemplated under this Section 9.4 shall relieve either Party of any obligations under this Agreement.

9.4.1 Cost Responsibility . Except as provided in Section 9.3.1, it is expressly understood that nothing herein shall be construed to in any way relieve EMC of, or impose upon Duke, the responsibility for any fees, costs, or charges (including but not limited to congestion costs, transmission losses, or the costs or charges to secure financial transmission rights or the equivalent thereof) that may be imposed on EMC by an ISO, RTO, ITC or other future organization, agency or authority that has been approved by FERC to serve as the Transmission Provider in connection with the provision of Transmission Service or Ancillary Services. It is further expressly understood that Duke shall have no right or interest in any financial transmission rights or the equivalent thereof that are allocated, assigned, transferred or acquired by EMC.

9.4.2 Congestion Costs . In the event that the Transmission Provider implements a pricing methodology that allocates congestion costs on a locational basis, in determining the dispatch order of Duke’s Generation System, Duke shall make no adverse distinction between Duke’s Native Load and Duke’s obligations to supply FFR Supplemental Service or Partial Requirements Service, as applicable under this Agreement. Duke further agrees that, in the event it designates Delivery Points for Duke’s Generation System, Duke shall make no adverse distinction between Duke’s Native Load and Duke’s obligations to supply FFR Supplemental Service or Partial Requirements Service, as applicable under this Agreement. The Parties shall reasonably cooperate with each other in an effort to develop and implement congestion management strategies designed to minimize the incurrence of congestions costs associated with the delivery of electric energy under this Agreement. Duke will provide EMC with recommended strategies to manage such congestion costs, under terms that would not subject Duke’s Native Load to any costs that Duke would not otherwise incur, and if EMC agrees with such recommendation, Duke will use Commercially Reasonable Efforts to implement the recommended congestion management strategies. Duke shall also use Commercially Reasonable Efforts to comply with the congestion management rules that may be adopted by the Transmission Provider.

Article 10

Operating Committee

10.1 Operating Committee . The Parties shall establish an Operating Committee consisting of one (1) Representative each. The Operating Committee shall act only by unanimous agreement or consent. Duke and EMC shall designate their respective Representatives to the Operating Committee, plus any alternate, by written notice delivered in accordance with Section 16.22 within thirty (30) Days after the Effective Date. Each Party’s Representative on the Operating Committee is authorized to act on behalf of such Party with respect to any matter arising under this Agreement.

10.2 Duties of the Operating Committee . The Operating Committee shall facilitate the coordination and interaction between the Parties with respect to the performance of the duties and obligations imposed on the Parties hereunder, including development or revision of appropriate protocols and procedures therefor. The Operating Committee shall not, however, have any authority to modify or otherwise alter the Parties’ rights and obligations under this Agreement.

Article 11

Demand Side Management

11.1 Availability of Demand Side Management Resource Programs . EMC may make available to EMC’s Native Load customers EMC Demand Side Management Resource Programs to the same extent and under comparable terms and conditions as Duke’s Demand Side Management Resource Programs; provided, however, that EMC may not make available to EMC’s Native Load customers any demand side management resource programs or similar programs other than such EMC Demand Side Management Resource Programs unless EMC is otherwise required by RUS or by applicable Law to make other demand management side resource programs available to EMC’s Native Load customers or is otherwise permitted under Section 11.7. Except as set forth in Section 4.2.6, the terms and conditions of EMC Demand Side Management Resource Programs shall be applied to EMC’s Native Load customers and enforced by Duke in the same or comparable manner as they are applied to Duke’s Native Load retail customers and enforced by Duke. Except as set forth in Section 4.2.6, in implementing and operating such EMC Demand Side Management Resource Programs, Duke shall make no adverse distinction with respect to EMC’s Native Load.

11.2 Changes to Demand Side Management Resource Programs . Upon ninety (90) Days prior written notice, Duke shall advise EMC of any modifications, additions, or deletions that have been or will be made to the Demand Side Management Resource Programs, and the EMC Demand Side Management Resource Programs available hereunder to EMC’s Native Load customers shall be deemed to have been revised to reflect such modifications, additions, or deletions without any further action required by either Party.

11.3 Credits . Except for any EMC Demand Side Management Resource Program implemented pursuant to Section 11.7 of this Agreement, for each EMC Native Load customer

that implements an EMC Demand Side Management Resource Program, EMC shall be entitled to a billing credit. Such billing credit shall be calculated in accordance with the credit applicable for the Demand Side Management Resource Program, as specified in the rider approved and on file with NCUC for such Demand Side Management Resource Program. Each Month, Duke shall aggregate the total billing credits to which EMC is entitled pursuant to this Section 11.3, and provide EMC a credit on the Monthly statement delivered in accordance with Section 13.2 equal to the total billing credits for such Month.

11.4 Necessary Arrangements . To the extent that an EMC Native Load customer agrees to implement an EMC Demand Side Management Resource Program, the Parties shall cooperate in preparing any detailed implementation procedures and arrangements required to implement such program, provided that, except for any EMC Demand Side Management Resource Program implemented pursuant to Section 11.7 of this Agreement, Duke shall retain sole operational control over such EMC Demand Side Management Resource Program implemented. The failure of the Parties to agree on detailed implementation procedures and obligations shall not affect Duke’s obligation to provide EMC with credits as determined by Section 11.3.

11.4.1 Audits . For each EMC Demand Side Management Resource Program whose credit depends upon the number of EMC Native Load customers, EMC shall be required to provide Duke written notice, by no later than January 31 of each Year, of the number of EMC Native Load customers with whom EMC has entered into arrangements pursuant to this Section 11.4 for such EMC Demand Side Management Resource Program. Duke shall have the right periodically to perform audits, in accordance with the terms of Section 13.6, to verify the accuracy of the notices concerning the number of EMC Native Load customers with whom EMC has entered into arrangements for each EMC Demand Side Management Resource Program. Based on the results of such audits, Duke shall be entitled, in accordance with the terms of Section 13.2.2, to revise or adjust the level of credits that Duke previously had provided EMC.

11.5 Start-Up Conditions . No later than sixty (60) Days after the Effective Date, Duke shall conduct a system-wide test of each EMC Demand Side Management Resource Program to determine its capability. Duke shall provide EMC with the results of such test no later than five (5) Business Days after the completion of the system-wide test. Duke shall not be required to provide credits for EMC Demand Side Management Resource Programs unless the applicable standards and requirements specified for Duke’s Demand Side Resource Management Programs under the riders approved and on file with the NCUC shall have been met, and the testing provided for in this Section 11.5 shall have been accomplished.

11.6 Periodic Testing . Duke shall have the right periodically, but no less than once per Year, to conduct a system-wide test of each EMC Demand Side Management Resource Program to determine whether the tested EMC Demand Side Management Resource Program is capable of providing a level of demand reduction equal to the level of the credit that EMC is, at the time of such system-wide test, receiving for such EMC Demand Side Management Resource Program. Subject to Section 11.6.1, if, at the time of such system-wide test, one or more EMC Demand Side Management Resource Program(s) do not provide the level of demand reduction equal to the level of the credit that EMC is receiving for such EMC Demand Side Management Resource Program(s), Duke shall have the right to (i) reduce the credit provided to EMC to the actual level of demand reduction provided at the time of the system-wide test and, in accordance with the

terms of Section 13.2.2, to revise or adjust the level of credits that Duke previously had provided EMC, and (ii) provide written notice within ninety (90) Days of the system-wide test, to cancel such EMC Demand Side Management Resource Program(s).

11.6.1 Retesting . Within sixty (60) Days of any failure of a system-wide test for an EMC Demand Side Management Resource Program, EMC shall have the right to have Duke conduct a retest in order to demonstrate that such EMC Demand Side Management Resource Program is capable of providing the level of demand reduction equal to the level of the credit that EMC previously was receiving for such EMC Demand Side Management Resource Program. To the extent that any such system-wide retest demonstrates that the EMC Demand Side Management Resource Program is capable of providing demand reduction, the credit provided to EMC shall be restored to the prior level or such lesser level as demonstrated by the result of such rescheduled test and, to the extent applicable, Duke shall, in accordance with the terms of Section 13.2.2, revise or adjust the level of credits that Duke previously had provided EMC and any notice to terminate rendered by Duke pursuant to 11.6 shall be null and void.

11.7 EMC Demand Side Management . If Duke’s Annual Planning Period shifts from the Summer Period to the Winter Period, then EMC shall have the authority to implement and call upon EMC Demand Side Management Resource Programs to control EMC’s Native Load demands coincident with the twenty (20) highest Hourly (integrated sixty-minute) Duke Schedule 1 Demands during the Winter Period to the level equal to but not below the average of (i) the average of EMC’s Native Load demands coincident with the twenty (20) highest Hourly (integrated sixty-minute) Duke Schedule 1 Demands during the immediately preceding Summer Period and (ii) the average of EMC’s Native Load demands coincident with the twenty (20) highest Hourly (integrated sixty-minute) Duke Schedule 1 Demands during the second preceding Summer Period. For example, if (i) the Annual Planning Period during May 2012 - April 2013 is the Summer Period (May 2012 - September 2012), and the average of EMC’s integrated sixty (60) minute EMC Native Load demands coincident with the twenty (20) highest Hourly Duke Schedule 1 Demands during such period is 100 MWs; and (ii) the Annual Planning Period during May 2013 - April 2014 is the Winter Period (October 2013 - April 2014), and the average of EMC’s integrated sixty (60) minute EMC Native Load demands coincident with the twenty (20) highest Hourly Duke Schedule 1 Demands during the Summer Period immediately preceding such Winter Period (i.e., May 2013 - September 2013) is 102 MWs; then EMC may call upon EMC Demand Side Management Resource Programs to control EMC’s integrated sixty (60) minute EMC Native Loads demands coincident with the twenty (20) highest Hourly Duke Schedule 1 Demands during October 2013 - April 2014 to the level equal to but not below 101 MWs. It is expressly acknowledged that (a) Duke shall also have the right to call upon any available EMC Demand Side Management Resource Program implemented pursuant to this Section 11.7, and (b) EMC shall not be entitled to a billing credit under Section 11.3 (or any other provision of this Agreement) in connection with any EMC Demand Side Management Resource Program implemented pursuant to this Section 11.7.

Article 12

Modification of This Agreement

12.1 Unilateral Modification . Except as provided in Section 12.3:

No unilateral modification, amendment or other change to the terms of this Agreement shall be permitted or deemed effective for any reason, and the rates, terms and conditions specified herein shall not be subject to change through application to FERC pursuant to the provisions of Sections 205 or 206 of the Federal Power Act absent the written agreement of both Parties. Any amendment or modification to this Agreement shall be deemed enforceable if and only if such amendment or modification (a) has been reduced to writing, (b) has been agreed to and duly executed by both Parties in writing, and (c) has received all requisite approvals of Governmental Authorities necessary for the effectiveness thereof. Each Party hereby irrevocably waives its rights, including any rights under Sections 205 and/or 206 of the Federal Power Act, to file a complaint, request an investigation, or make any unilateral rate-change request seeking: (a) an order from FERC finding that any rate or provision in this Agreement is unjust or unreasonable; (b) any refund with respect to this Agreement’s rates; or (c) any other unilateral modification to this Agreement. Each Party agrees not to make any such unilateral filing or request, and agrees and warrants that these covenants and waivers shall be binding notwithstanding any regulatory, market, or other change that may occur at any time during the Term.

12.2 Mobile-Sierra Public Interest Standard . Except as provided in Section 12.3, to the extent this Agreement is challenged by any person or its terms are subjected to review under the Federal Power Act or other Laws, the “just and reasonable” standard shall not apply. Instead, absent the agreement of both Parties to the proposed change, and except as provided in Section 12.3, the standard of review for changes to this Agreement proposed by a Party, a non-party, or FERC acting sua sponte shall be the “public interest” standard of review set forth in United Gas Pipe Line Co. v. Mobile Gas Service Corp. , 350 U.S. 332 (1956); Federal Power Commission v. Sierra Pacific Power Co. , 350 U.S. 348 (1956).

12.3 Changes To Certain Charge Components . Notwithstanding anything else herein to the contrary, nothing contained herein shall be construed as affecting in any way the right of either Party to unilaterally make application to FERC under Sections 205 or 206 of the Federal Power Act (i) to change the depreciation rates and nuclear decommissioning accrual used in Schedule 1 , (ii) to include additional cost items that are incurred in providing FFR Supplemental Service or Partial Requirements Service, as applicable, to EMC that are not included in Schedule 1 , (iii) to exclude from Schedule 1 cost items that are no longer incurred in providing FFR Supplemental Service or Partial Requirements Service, as applicable to EMC, or (iv) to change Schedule 1 to reflect changes in Duke’s accounting consistent with the Accounting Requirements (including the addition of new accounts and the removal of obsolete accounts). In addition, in the event that (a) EMC implements new time-of-use rates or materially modifies its existing time-of-use rates, for some or all of EMC’s Native Load customers, (b) such rates result in a reduction of EMC’s Monthly Billing Demand under Sections 7.2.6.3.2 or 7.3.2.2, and (c) such Monthly Billing Demand reduction does not result in a commensurate reduction in the EMC demands that Duke utilizes in Duke’s Generation Planning Practices, Duke may make unilateral application to

FERC under Section 205 of the Federal Power Act to change the calculation of the Monthly Billing Demand set forth in Sections 7.2.6.3.2 or 7.3.2.2 to more appropriately reflect the costs that Duke incurs in providing service under this Agreement. In the event that Duke makes such a filing with FERC, EMC may oppose such filing, and, in addition, shall be free to propose any other method for calculating the Monthly Billing Demands set forth in Sections 7.2.6.3.2 or 7.3.2.2 to more appropriately reflect the costs that Duke incurs in providing service under this Agreement.

12.4 Standard of Review for Permitted Changes . The Parties acknowledge that, as of the Effective Date, FERC has issued a proposed rule that, if adopted, would specify the language for parties to include in future agreements where the parties intend that the “just and reasonable” standard of review apply to amendments to the agreements. Notwithstanding the language that ultimately may be adopted by FERC, it is the intent of the Parties that the standard of review that FERC shall apply when acting on proposed modifications to this Agreement that are permitted under Section 12.3, either on FERC’s own motion or on behalf of a signatory or non-signatory, shall be the “just and reasonable” standard of review rather than the “public interest” standard of review.

12.5 Scope of Waiver . Nothing in this Article 12 shall be construed to modify or limit any Party’s right to enforce the express terms of this Agreement as they are written in this Agreement.

Article 13

Billing and Payment

13.1 Billing Period . Unless otherwise specifically agreed upon by the Parties in the terms of this Agreement or otherwise in writing, the Month shall be the standard period for determining all billings and payments under this Agreement.

13.2 Billing Statements .

13.2.1 Initial Statements . After the end of each Billing Period, Duke shall deliver to EMC a statement setting forth for the Billing Period (i) the sum of the electric energy delivered and/or received for all Hours during that Billing Period, and (ii) Duke’s calculation of any amounts due from EMC under this Agreement for the Billing Period. In addition, in the event that there are amounts due from Duke to EMC under this Agreement for a Billing Period, EMC shall deliver to Duke, after the end of such Billing Period, a statement setting forth for the Billing Period EMC’s calculation of any amounts due from Duke under this Agreement for the Billing Period. Notwithstanding the foregoing, a Party’s failure to render a statement as set forth above shall not relieve the other Party from its obligation to make payment to the billing Party when such statement is rendered, provided such statement is rendered within one (1) year after the end of the Billing Period.

13.2.2 Subsequent Payment Adjustments . The Parties understand that in certain cases Monthly billings will need to be made on an estimated basis. In addition, the Parties understand that after-the-fact adjustments to amounts owed or revenues received may be made in order to

reflect correctly the amounts payable by one Party to the other under this Agreement. Each Party shall cooperate in good faith with the other Party to obtain the requisite information and perform the necessary computations so as to true-up or otherwise adjust any estimated or adjusted billings promptly.

13.3 Timeliness of Payment . Unless otherwise agreed by the Parties, all statements rendered under this Agreement, whether by Duke or EMC, shall be due and payable in accordance with each Party’s statement instructions on or before the later of the twentieth (20 ^th ) Day of each Month, or the tenth (10 ^th ) Day after receipt of the statement or; if such Day is not a Business Day, then on the next Business Day. Each Party shall make payments in immediately available funds by electronic funds transfer, or by other mutually agreeable method, to the account designated in writing by the other Party. Any non-disputed amounts (other than amounts for which payment may be withheld pursuant to Section 13.5) not paid by the due date shall be deemed delinquent and shall accrue interest at the Interest Rate, such interest to be calculated from and including the due date to but excluding the date the delinquent amount is paid in full.

13.4 Netting of Payments . The Parties hereby agree that they shall discharge mutual debts and payment obligations due and owing to each other on the same date through netting, in which case all amounts owed by each Party to the other Party under this Agreement during the Billing Period, including any related interest, payments, and credits, shall be netted so that only the excess amount remaining shall be paid by the Party who owes it. If no mutual debts or payment obligations exist and only one Party owes a debt or obligation to the other Party during the Monthly Billing Period, including but not limited to any interest, payments, or credits, that Party shall pay such sum in full when due.

13.5 Disputes and Adjustments of Statements . A Party may, in good faith, dispute the correctness of any statement or any adjustment to a statement, rendered under this Agreement or adjust any statement for any arithmetic or computational error within twenty-four (24) Months of the date the statement, or adjustment to a statement, was rendered. If a statement or portion thereof, or any other claim or adjustment arising under this Agreement is disputed, the disputing Party shall provide written notice to the other Party (the “Billing Dispute Notice”) which (a) states the good faith basis for the dispute, (b) specifies the amount in dispute (the “Disputed Amount”), if any, and (c) provides documentation reasonably supporting the determination of the Disputed Amount. The disputing Party shall, at its option, (a) make payment to the other Party of the Disputed Amount under protest and thereafter shall be reimbursed by the other Party for any amount determined to be refundable after the resolution of such dispute or (b) withhold one half (1/2) of the Disputed Amount and make payment to the other Party of the other one half (1/2) of the Disputed Amount. Payment to the other Party of one half (1/2) of the Disputed Amount shall not relieve the disputing Party of the obligation to pay interest accrued at the Interest Rate from and including the date such payment was due to but excluding the date of such payment of any portion of such Disputed Amount withheld and determined to be due and payable after the resolution of such dispute. Likewise, the other Party shall not be relieved of the obligation to pay interest accrued at the Interest Rate from and including the date such payment was made to but excluding the date of reimbursement of any portion of such Disputed Amount paid and determined to be refundable after the resolution of such dispute.

In the event that a Party, by timely notice to the other Party, disputes the correctness of a statement or portion thereof or any other claim or adjustment arising under this Agreement, the other Party shall promptly review the disputed statement or adjustment and shall notify the disputing Party, within forty-five (45) Days following receipt of the Billing Dispute Notice, of the amount of any error or the amount of any payment or reimbursement that the disputing Party is required to make or is entitled to receive. Payments determined to be due by the disputing Party shall be included on the next Monthly statement, and shall include interest accrued at the Interest Rate from and including the due date to but excluding the date paid. Reimbursements determined to be due from the other Party shall be included on the next Monthly statement, and shall include interest accrued at the Interest Rate from and including the due date to but excluding the date reimbursed. If the disputing Party disagrees with the other Party’s resolution of any dispute, then the Parties shall submit the dispute for resolution in accordance with Article 14.

Inadvertent overpayments shall be returned upon request or deducted by the Party receiving such overpayment from subsequent payments, with interest accrued at the Interest Rate from and including the date of such overpayment to but excluding the date repaid or deducted by the Party receiving such overpayment. Any dispute with respect to a statement is waived unless the other Party is notified in accordance with this Section 13.5 within twenty-four (24) Months after the statement is rendered or any adjustment to the statement is made. Neither Party shall have the right to challenge any statement, to invoke arbitration of the same or to bring any court or administrative action of any kind questioning the propriety or any other aspect of such statement after a period of twenty-four (24) Months from the date the statement was rendered; provided, however, that in the case of a statement containing estimates, such twenty-four (24) Month period shall run from the date the statement is adjusted to reflect the actual amounts due.

13.6 Records and Audits . Each Party shall keep such records and documents as may be needed to afford a clear and complete history of all transactions under this Agreement, and the cost information used to calculate the charges for such transactions, for twenty-four (24) Months following the Month in which such transaction occurs. In addition, during such twenty-four (24) Month period, EMC shall have the right to audit all records, including phone and computer records, related to Duke’s performance of its obligation not to adversely distinguish against EMC’s Native Load under Section 4.3.3, Section 6.2, and Section 9.4.2 of this Agreement. If a Party initiates an audit through a notice to the other Party within the time period provided herein, the records and documents related to such audit are required to be maintained under this Section 13.6, then the other Party will retain such records and documents until such audit is complete. If a Party issues an Original Notice pursuant to Article 14, then the Parties will retain the records and documents relating to such dispute until the resolution of such dispute. In maintaining such records and documents, EMC and Duke may rely upon the logs and other meter information routinely recorded by Transmission Providers or utilities responsible for coordination of the purchases and sales. During such twenty-four (24) Month period, either Party, or any Representatives of such Party, shall have the right, at its sole expense and during normal working Hours, to examine the records of the other Party, including documents and records held by third parties, to the extent reasonably necessary to verify the accuracy of any statement, charge, or computation made pursuant to this Agreement. The Party requesting the audit shall pay the costs associated with any independent auditor. Upon the request of the auditing Party, the document custodian of the other Party shall certify to the auditing Party that,

to the best of such person’s knowledge after reasonable investigation, the documents and records supplied are true and complete and, in the case of copies, are true, complete and correct copies of the original documents requested by the auditing Party.

13.6.1 Procedures . EMC may make a written request for Duke to provide access to documents and records to verify the accuracy of any statement, charge or computation made pursuant to this Agreement. Within ten (10) Business Days of the receipt of a written request from EMC, Duke shall either provide EMC, or its Representative, with access to the documents and records which are the subject of the written request or provide EMC with copies of the original documents and records. If Duke elects to provide EMC, or its Representative, with access to the documents and records requested by EMC, EMC or its Representative shall be permitted to make, at its own expense, copies of the documents and records to which it or its Representative has been provided access. Any copies made by EMC or its Representative shall be subject to the confidentiality provisions set forth in Section 16.6. If Duke is unable to provide EMC with access or copies within ten (10) Business Days of the receipt of EMC’s written request because it is unable to locate or gain access to such documents and records after reasonable investigation, Duke shall, within ten (10) Business Days of the receipt of such written request, provide EMC with notice describing the reasons for its failure to provide access to or copies of the documents and records, its efforts to obtain such documents and records, and its best estimate of the time in which EMC will be permitted access to or provided copies of such documents and records. The twenty-four (24) Month period provided for in Section 13.5 shall be tolled from the date Duke gives notice describing the reasons for its failure to provide access to or copies of the documents and records until Duke shall have (i) provided EMC with copies or access to all documents and records specified in EMC’s written request or (ii) Duke’s document custodian shall have certified, that to the best of his knowledge after reasonable investigation that such document does not exist or Duke cannot locate or produce such document or records.

13.6.2 Adjustments Resulting from Audits . If any audit or examination under this Section 13.6 reveals any inaccuracy in any statement, the necessary adjustments in such statement and the payments thereof shall be made promptly and shall accrue interest at the Interest Rate from the date the overpayment or underpayment was made until paid; provided, however, that no adjustment for any statement or payment shall be made unless objection to the accuracy thereof was made prior to the lapse of twenty-four (24) Months from the rendition thereof, and thereafter any objection shall be deemed waived.

13.6.3 Confidentiality . The auditing Party shall keep confidential any information obtained in the audit. If requested, a Party shall provide to the other Party statements evidencing the quantity of electric energy provided under this Agreement for up to the prior twenty-four (24) Months. If an audit is requested with respect to any records held by the a Party or a third party and those records cannot be disclosed to the requesting Party as a result of a confidentiality obligation, then to the extent legally permissible, the auditing Party shall select an independent auditor to perform the audit consistent with the Parties’ rights under this Agreement and with such confidentiality arrangements as may be required by the confidentiality obligation in question.

Article 14

Dispute Resolution

14.1 Arbitration . Except as otherwise provided below, any dispute arising out of or in connection with this Agreement or its performance that cannot be resolved after good faith discussions and negotiations between the Parties as set forth in Section 14.2 shall be submitted to binding arbitration. A dispute with respect to whether a Material Adverse Ruling meets the materiality standard specified in Section 2.3.2.2(c)(1) or (c)(2) shall be subject to dispute resolution pursuant to Section 2.3.2.2.2. A dispute with respect to an invoice shall first be subject to the procedures set forth in Section 13.5, and if such dispute is not resolved in accordance with such procedures, then such dispute shall be submitted to binding arbitration in accordance with this Article 14. Any arbitration commenced under this Article 14 shall be conducted in accordance with the North Carolina Arbitration Act, N.C.G.S. Section 1-567 et seq. , and the non-administered arbitration rules and procedures of the CPR Institute for Dispute Resolution (“CPR”) in effect at the time arbitration is commenced, except where specifically modified by this Agreement.

14.2 Negotiation and Notice of Arbitration . Prior to initiating arbitration hereunder, a Party shall provide the other Party with written notice of the dispute, a proposed means for resolving the same, and support for the Party’s position (“Original Notice”). Thereafter, Representatives of the Parties shall meet in person to discuss the matter and attempt in good faith to reach a negotiated resolution of the dispute. The Parties agree to provide and exchange supporting facts, records and information regarding the dispute (including calculation and bases) as part of the good faith negotiations. If the Parties have not agreed upon a resolution of the dispute within thirty (30) Days after the provision of the Original Notice or such other time period as the Parties may agree in writing to allow for discussions and negotiation (“Negotiation Period”), then at any time after the end of the Negotiation Period, a Party may provide written notice to the other declaring an impasse (“Impasse Notice”) and initiating binding arbitration in accordance with the further provisions of this Article 14. A Party providing an Impasse Notice shall also contemporaneously notify all entities within the EMC Group of the provision of its Impasse Notice.

14.3 Individual, Joint or Consolidated Arbitration . If, within thirty (30) Business Days of EMC’s provision of an Impasse Notice, Blue Ridge and/or Rutherford also provides an Impasse Notice relating to substantially the same issue as raised by EMC’s Impasse Notice, or if Duke contemporaneously provides each of EMC, Blue Ridge and/or Rutherford an Impasse Notice relating to substantially the same issue, then each entity within the EMC Group shall have ten (10) Business Days following the expiration of such thirty (30) Business Day period to provide written notification to Duke stating whether or not such entity will voluntarily proceed in a joint or combined arbitration.

If EMC and one or more of the entities within the EMC Group that have provided or received Impasse Notices within the specified time period relating to substantially the same issue elect to proceed individually or in more than one arbitration proceeding, Duke shall have the right to file a motion to consolidate such Impasse Notices with EMC’s Impasse Notice in a single proceeding. The motion to consolidate such Impasse Notices shall be served within ten (10)

Business Days of the date when each entity within the EMC Group has provided notice as to whether or not it will voluntarily proceed in a consolidated arbitration. Duke’s motion to consolidate shall be decided in the first commenced arbitration by one arbitrator (if the Streamlined Arbitration Process is used) or one (1) arbitration panel (if the Standard Arbitration Process is used), provided that the arbitrator(s) shall satisfy the qualifications required pursuant to the third sentence of Section 14.6.1(1) or Section 14.6.2(2), as applicable, with respect to all entities in the arbitration proceedings that are the subject of the motion to consolidate. If Impasse Notices are simultaneously given by EMC and one or more other entities within the EMC Group, then Duke shall have sole discretion to designate which of the Impasse Notices shall be treated as the first given for purposes of determining which arbitrator(s) shall decide the motion to consolidate, and shall provide written notice of such designation in the motion to consolidate arbitrations. The procedures set forth in Sections 14.6.1 and 14.6.2 for each arbitration proceeding in which the motion to consolidate was not filed shall be held in abeyance pending the decision on the motion to consolidate by the arbitrator(s) in the arbitration proceeding in which the motion to consolidate was filed.

In determining whether consolidation of one or all is appropriate, the arbitrator(s) shall consider whether the same or substantially similar issue or issues will be subject to the arbitration(s); EMC’s reasons for opposing consolidation and Duke’s reasons for seeking consolidation; and the fundamental fairness and efficiency in proceeding individually, jointly or consolidated. The arbitrator(s) decision on the motion to consolidate shall be binding on the Parties and not subject to appeal.

In the event the motion to consolidate is denied (unless otherwise agreed by the Parties and the other entities of the EMC Group that have provided or received such Impasse Notices), the arbitrations shall each proceed, subject to resolution of scheduling issues, with no arbitration being stayed as a result of the denial of the motion. In the event the motion to consolidate is granted, each entity within the EMC Group, other than the entity which is a party to the proceeding in which the motion to consolidate was filed, shall move for dismissal of the respective arbitration actions in which it is a party.

14.3.1 Individual Treatment of EMC in Joint or Consolidated Arbitration . For purposes of joint or combined arbitration, all of the entities within the EMC Group participating in the proceeding shall be treated as one (1) Party for purposes of Article 14, with the following exceptions. First, EMC shall be treated as a separate Party for purposes of Selection of Arbitration Process set forth in Section 14.4. Second, EMC may reach its own independent, voluntary resolution with Duke and may pursue its own strategy and prosecute its case with its own legal counsel in the joint or combined arbitration. Third, EMC will be treated as a separate Party for purposes of discovery in Section 14.6.1(4) or 14.6.2(4). Fourth, EMC will be treated as a separate Party for purposes of a Submission and for the adoption of the resolution and the associated monetary amount with respect to the ultimate decision of the arbitrator(s). Fifth, EMC will be treated as a separate Party for purposes of the third sentence of Section 14.6.1(1) and Section 14.6.2(2).

14.4 Selection of Arbitration Process . No later than thirty (30) Days following receipt of the Impasse Notice, or any longer time period as agreed to by the Parties, the Parties shall agree on which arbitration process specified herein to use: either the Standard Arbitration Process or the

Streamlined Arbitration Process. Should the Parties fail to agree on the arbitration process within thirty (30) Days following receipt of the Impasse Notice, then the Standard Arbitration Process shall be used; provided however, that the Streamlined Arbitration Process shall be used for any dispute where the damages in dispute or other monetary value at stake is alleged to be two hundred fifty thousand dollars ($250,000) or less for EMC or Duke, or in a joint or combined proceeding two hundred and fifty thousand dollars ($250,000) or less for each entity within the EMC Group that is participating in the proceeding. If the damages in dispute or other monetary value at stake in a combined proceeding is alleged to be two hundred fifty thousand dollars ($250,000) or less for EMC and at least one (1) other of the entities within the EMC Group participating in a joint or combined proceeding, the Streamlined Arbitration Process shall be used upon the request of either Party (or any of the other entities within the EMC Group participating in the proceeding) made within thirty (30) Days following the receipt of the Impasse Notices.

14.5 Initiation of Arbitration . Unless otherwise agreed by the Parties and except as provided for in Section 14.3, arbitration shall be deemed to be initiated when the arbitration process is agreed upon or otherwise determined pursuant to Section 14.4 (“Selection Date”).

14.6 Arbitration Processes .

14.6.1 Standard Arbitration Process . The following shall be the process that is used, in accordance with this Article 14, as the Standard Arbitration Process under this Agreement. By mutual agreement, the Parties may in any given arbitration and for the purposes of that arbitration alone modify or forego any procedural requirement or rule specified hereunder as part of the Standard Arbitration Process:

(1) Selection of Arbitrators . The Party initiating arbitration shall nominate one (1) arbitrator no later than fifteen (15) Days following the Selection Date. The other Party shall nominate one (1) arbitrator no later than thirty (30) Days after the Selection Date. Each of the two Party-nominated arbitrators shall be unaffiliated with any of the Parties or their predecessors or Affiliates; shall not be current or former employees of the nominating Party or its predecessors or Affiliates and shall be without material financial alliance with the nominating Party or its predecessors or Affiliates such that said arbitrator is able to participate in the arbitration without evident partiality or actual bias in favor of the nominating Party; unless such pecuniary interest or affiliation is expressly acknowledged and waived by all Parties. The two (2) arbitrators shall jointly appoint a third (3 ^rd ) , neutral arbitrator within thirty (30) Days after the nomination of the second (2 ^nd ) arbitrator. The neutral arbitrator shall be the chairperson of the tribunal. This thirty (30) Day period may be extended to sixty (60) Days by agreement of both Parties. If the two (2) arbitrators are unable to agree on a third (3rd) arbitrator within the specified time period, then a third (3rd) arbitrator shall be selected by the CPR with due regard given to the selection criteria herein and in the subsequent subsections of Article 14 and input from the Parties and other arbitrators. The Parties shall request CPR to complete selection of the third (3 ^rd ) arbitrator no later than thirty (30) Days following their request for selection of the arbitrator. Costs charged by CPR for this service shall be borne one-half (1/2) by Duke and one-half (1/2) by EMC; provided that if the arbitration proceeds as a consolidated proceeding pursuant to Section 14.3, the costs charged by CPR shall be

borne one-half (1/2) by Duke and one-half (1/2) by the entities within the EMC Group that participate in such consolidated arbitration. In the event CPR should fail to select the third (3 ^rd ) arbitrator within thirty (30) Days following the Parties’ request for selection of the arbitrator, then any Party may petition a court of competent jurisdiction in the State of North Carolina to select the third (3 ^rd ) arbitrator. Due regard shall be given to the selection criteria and input from the Parties and other arbitrators. Each of the arbitrators shall take an oath of neutrality.

(2) Additional Qualifications of Arbitrators . Unless otherwise agreed to by the Parties, each of the arbitrators shall be competent and experienced in matters involving the electricity business in the United States. Such experience shall be conclusively demonstrated by ten (10) years or more of electric industry experience as a practicing attorney or other experience or expertise as agreed to by the Parties.

(3) Replacement of Arbitrators . If prior to the conclusion of the arbitration any arbitrator becomes incapacitated or otherwise unable to serve, then a replacement arbitrator with the qualifications specified herein shall be appointed in the manner and timeframe (such timeframe starting anew following the unavailability of the arbitrator to be replaced) described in Section 14.6.1(1) above.

(4) Discovery . Discovery and other pre-hearing procedures shall be conducted as set forth herein, as otherwise agreed by the Parties, or if they cannot agree, as determined by a majority of the arbitrators. Each Party shall have the right to propound up to ten (10) interrogatories, the right to request relevant documents and records, conduct depositions (including depositions of experts), designate experts, and obtain the opinion of opposing experts.

(5) Hearing . Within fifteen (15) Days after completion of discovery, each Party shall contemporaneously submit by overnight delivery and electronic mail to the arbitrators a precise statement of the dispute, a proposed resolution of the dispute, including a monetary amount and the supporting calculations if applicable, and the factual and/or legal support therefor (the “Submission”). The next Business Day the Parties shall exchange complete Submissions by overnight delivery and electronic mail. Within fifteen (15) Days after receiving the other Party’s Submission, each Party may submit by overnight delivery and electronic mail to the other Party and the arbitrators a reply statement to the other Party’s Submission. The Parties shall conduct a hearing in Charlotte, North Carolina no later than the later of (i) sixty (60) Days following selection of the third (3 ^rd ) arbitrator, (ii) forty-five (45) Days after all pre-hearing discovery has been completed, or (iii) forty-five (45) Days after the issuance of the arbitrators’ decision denying a motion to consolidate pursuant to Section 14.3, at which the Parties shall present such evidence, argument, and witnesses as they may choose. Prior to the beginning of the hearing, the Parties may submit a joint statement of undisputed facts and/or issues to be resolved, if the Parties so agree to submit such statement or if the arbitrators order submission of the statement. If the Parties agree, or if allowed by a majority of the arbitrators, the Parties each may submit a post-hearing brief to the arbitrators within ten (10) Business Days of completion of the hearing. No reply briefs shall be allowed unless otherwise permitted by a majority of the arbitrators.

14.6.2 Streamlined Arbitration Process . The following shall be the process that is used, in accordance with this Article, as the Streamlined Arbitration Process under this Agreement. By mutual agreement, the Parties may in any given arbitration and for the purposes of that arbitration alone modify or forego any procedural requirement or rule specified hereunder as part of the Streamlined Arbitration Process:

(1) Selection of Arbitrator . No later than thirty (30) Days following the Selection Date, the Parties shall agree upon a single arbitrator to conduct the arbitration. If the Parties are unable to agree on an arbitrator, then the arbitrator shall be selected by the CPR with due regard given to input from the Parties and in conformity with the qualifications specified herein. The Parties shall request CPR to complete selection of the arbitrator no later than thirty (30) Days following their request for selection of an arbitrator. Costs charged by CPR for this service shall be borne one-half (1/2) by Duke and one-half (1/2) by EMC; provided that if the arbitration proceeds as a consolidated proceeding pursuant to Section 14.3, the costs charged by CPR shall be borne one-half (1/2) by Duke and one-half (1/2) by the entities within the EMC Group that participate in such consolidated arbitration. In the event CPR should fail to select the arbitrator within seventy-five (75) Days after the Selection Date, then any Party may petition a court of competent jurisdiction in the State of North Carolina to select the arbitrator. Due regard shall be given to the selection criteria and input from the Parties. The arbitrator shall take an oath of neutrality.

(2) Qualification of the Arbitrator . The arbitrator shall be unaffiliated with any of the Parties or their predecessors or Affiliates, such that the arbitrator:

(a) Shall not be a current or former employee, advisor, attorney or consultant;

(b) Shall be without material financial alliance, such that said arbitrator is able to participate in the arbitration without evident partiality or bias, unless such pecuniary interest or affiliation is expressly acknowledged and waived by all Parties;

(c) Shall be competent in matters involving the electricity business in the United States and shall have ten (10) years or more of electric industry experience as a practicing attorney or such other experience or expertise as agreed by the Parties; and

(d) Shall take an oath of neutrality.

(3) Replacement of Arbitrator . If prior to the conclusion of the arbitration the arbitrator becomes incapacitated or otherwise unable to serve, then a replacement arbitrator with the qualifications specified herein, shall be appointed in the manner and timeframe (such timeframe starting anew following the unavailability of the arbitrator to be replaced) described in Section 14.6.2(1) above.

(4) Discovery . Discovery and other pre-hearing procedures shall be conducted as set forth herein, as otherwise agreed by the Parties, or if they cannot agree,

as determined by the arbitrator. Each Party shall have the right to propound up to ten (10) interrogatories, the right to request relevant documents and records, conduct at least three (3) depositions, in addition to obtaining discovery of the opinions of any experts and the right to depose any experts (which are not included in the three (3) depositions above). Additional discovery may be conducted only as allowed by the arbitrator or agreed by the Parties.

(5) Hearing . Within fifteen (15) Days after completion of discovery, each Party shall contemporaneously submit a Submission by overnight delivery and electronic mail to the arbitrator. The next Business Day, the Parties shall exchange complete Submissions by overnight delivery and electronic mail. Within fifteen (15) Days after receiving the other Party’s Submission, each Party may submit by overnight delivery and electronic mail to the other Party and the arbitrator a reply statement to the other Party’s Submission. The Parties shall conduct a hearing in Charlotte, North Carolina no later than the later of (i) forty-five (45) Days following selection of the arbitrator, (ii) forty-five (45) Days after all pre-hearing discovery has been completed, or (iii) forty-five (45) days after the issuance of the arbitrator(s)’ decision denying a motion to consolidate pursuant to Section 14.3, at which the Parties shall present such evidence, witnesses, and argument as they may choose. Unless otherwise ordered by the arbitrator, at least two (2) Days prior to the beginning of the hearing, the Parties may submit a joint statement of undisputed facts and/or issues to be resolved if the Parties so agree to submit such statement or if the arbitrator orders submission of the statement. If the Parties agree, or if allowed by the arbitrator, the Parties may each submit a post-hearing brief to the arbitrator within ten (10) Business Days of completion of the hearing. No reply briefs shall be allowed unless otherwise permitted by the arbitrator.

14.7 Decision . The arbitrator (if the Streamlined Arbitration Process is used) or a majority of the arbitrators (if the Standard Arbitration Process is used) shall render his or their decision in favor of one Party or the other by adopting the resolution and the associated monetary amount requested by the prevailing Party in its Submission. The arbitrator(s) must determine the prevailing Party by interpreting the meaning and intent of the language of this Agreement, applying the applicable Law to the relevant facts and selecting the arbitration ruling proposed by the Parties that most closely correlated to their decision based upon this Agreement, the applicable Law and the relevant facts. In rendering the decision, the arbitrator(s) shall interpret and apply the terms and conditions of this Agreement, and consider any relevant evidence and testimony, but shall not have the power to add to or modify any provision of this Agreement or to recommend any additions or modifications or to render a decision that does not adopt the resolution and the associated monetary amount requested by the prevailing Party in its Submission. The arbitrator(s) shall render a decision within thirty (30) Days following the later of the conclusion of the hearing or the submission of post-hearing briefs. The decision shall be rendered in writing and shall be final and binding upon the Parties. The decision may be filed in a court of competent jurisdiction, confirmed and may be enforced by any Party as a final judgment in such court, but shall have no precedential effect on future arbitrations under or arising out of this Agreement except for purposes of enforcement in a court of competent jurisdiction or for the assertion of collateral estoppel/issue preclusion or res judicata /claim preclusion in another proceeding. The Parties expressly acknowledge that no appeal of the arbitrator’s (or arbitrators’) decision shall be allowed. Except as provided in Section 16.6.4 of this Agreement, the arbitrator(s) shall have no authority to award special, exemplary, punitive, or consequential damages.

14.8 Expenses . The compensation and expenses of the arbitrator(s) shall be chargeable to and borne one-half (1/2) by Duke and one-half (1/2) by EMC; provided, that if the arbitration proceeds as a consolidated proceeding pursuant to Section 14.3, the costs charged by CPR shall be borne one-half (1/2) by Duke and one-half (1/2) by the entities within the EMC Group that participate in such consolidated arbitration; provided, however, that each Party shall bear the compensation and expenses of its own counsel and any retained or expert witnesses. Any costs incurred by a Party in seeking judicial enforcement of any final decision rendered by arbitration conducted under this Article 14 shall be chargeable to and borne exclusively by the Party against whom such court order is obtained. It is expressly acknowledged that the failure of the entities within the EMC Group that participate in a consolidated arbitration to reach agreement on the allocation of costs among such entities shall not increase Duke’s share of the costs incurred under this Section 14.8 or Sections 14.6.1(1) or 14.6.2(1) above one-half (1/2) of the total costs at issue.

14.9 Effect of Dispute Resolution Procedures . The initiation of the dispute resolution procedures under this Article 14 shall not affect the Parties’ respective obligations and rights under this Agreement during the pendency of any such procedures.

14.10 Confidentiality . The existence, contents, or results of any arbitration proceeding under this Article 14 shall be deemed to be Confidential Information and shall be subject to the confidentiality provisions set forth in Section 16.6.

Article 15

Credit and Collateral Requirements

15.1 Posting of Collateral . To protect either Party against potential default of payment or performance, any Party that experiences a Material Adverse Change (“MAC”) shall post as collateral an amount equal to the two (2) highest Months of Duke’s billings to EMC for the previous twelve (12) Months. Such collateral shall be provided by the Party experiencing the MAC in cash, depository agreements, or letters of credit from a financial institution reasonably acceptable to the Party not experiencing the MAC within three (3) Business Days after the date on which the MAC occurs. Any such depository agreement or letter of credit shall be in a form satisfactory to the Party not experiencing the MAC in its reasonable discretion. A financing institution participating in a depository agreement or providing a letter of credit entered into for purposes of this Section 15.1 shall be deemed reasonably acceptable by the Party not experiencing the MAC if it has and maintains a minimum long term credit rating of A- or better from S&P, A3 or better from Moody’s or A- or better from Fitch Ratings, or is with or from CFC and/or CoBank.

15.2 Material Adverse Change . Duke shall be deemed to have experienced a MAC if its unsecured, senior long-term debt obligations not supported by third party credit enhancements are rated below BBB- by S & P and below Baa3 by Moody’s. EMC shall be deemed to have experienced a MAC (a) if it fails to meet the then-current Debt Service Coverage Ratio required

of EMC by RUS, as determined by averaging the two (2) highest annual ratios during the most recent three (3) Years, and (b) the then-current Times Interest Earned Ratio required of EMC by RUS, as determined by averaging the two (2) highest annual ratios during the most recent three (3) Years. The failure by either Party to timely fulfill a payment or reimbursement obligation, including, in the case of Duke a failure to pay Cover Costs, under this Agreement also shall constitute a MAC by that Party.

15.3 Continuing Nature of Collateral Requirement . The Party experiencing the MAC must continue to post the collateral until the MAC is cured. The Party not experiencing the MAC shall have the right to draw upon, use, and dispose of all collateral that is posted under Section 15.1, if the Party experiencing the MAC fails to fulfill any of its payment or reimbursement obligations, including, in the case of Duke a failure to pay Cover Costs, under this Agreement, and such failure constitutes an Event of Default. In the event any collateral is drawn upon by the Party not experiencing the MAC in accordance with the provisions of Section 15.5, the Party experiencing the MAC shall within three (3) Business Days fully replenish the collateral to the monetary amount required by Section 15.1.

15.4 Interest on Cash Used as Collateral . Any interest earned on collateral held under a depository agreement with a financial institution shall be paid to the Party posting the collateral in accordance with the terms of the depository agreement. If cash collateral is posted, the Party holding the cash collateral shall pay interest to the Party posting the cash collateral at the Federal Funds Effective Rate. The Federal Funds Effective Rate is the rate for that Day opposite the caption “Federal Funds (Effective)” as set forth in the weekly statistical release designated as H.15(519), or any successor publication published by the Board of Governors of the Federal Reserve System. The Party posting the cash collateral shall invoice the Party holding the cash collateral for interest accrued during the previous Month and the Party holding the cash collateral shall pay such amount within ten (10) Days of receipt of such invoice.

15.5 Grant of Security Interest/Remedies . To secure their obligations under this Agreement, any Party posting collateral under Section 15.1 hereby grants to the Party not experiencing the MAC a present and continuing security interest in, and lien on (and right of setoff against), and assignment of, all cash collateral, cash equivalents collateral and any and all proceeds resulting therefrom or the liquidation thereof, whether now or hereafter held by, on behalf of, or for the benefit of, that Party, and the posting Party agrees to take such action as the non-posting Party reasonably requires in order to perfect the non-posting Party’s first-priority security interest in, and lien on (and right of setoff against), such collateral and any and all proceeds resulting therefrom or from the liquidation thereof. Upon or any time after the occurrence or deemed occurrence and during the continuation of an Event of Default, the Non-Defaulting Party may do any one or more of the following: (i) exercise any of the rights and remedies of a secured party with respect to all collateral, including any such rights and remedies under Law then in effect; (ii) exercise its rights of setoff against any and all property of the Defaulting Party in the possession of the Non-Defaulting Party or its agent; (iii) draw on any outstanding letter of credit issued for its benefit; and (iv) liquidate all collateral then held by or for the benefit of the Non-Defaulting Party free from any claim or right of any nature whatsoever of the Defaulting Party, including any equity or right of purchase or redemption by the Defaulting Party. The Party drawing upon the collateral shall apply the collateral drawn upon or otherwise realized upon the exercise of any rights or remedies granted under this Section 15.5, to reduce the obligations of

the Party posting the collateral under this Agreement (the posting Party remaining liable for any amounts owing after such application), and to return any surplus collateral or proceeds remaining after the posting Party’s obligations are satisfied in full.

15.6 Notice, Information . Each Party shall provide the other Party written notice within two (2) Business Days of the occurrence of an MAC affecting the notifying Party or of the occurrence of any event that may reasonably cause a MAC. Duke shall provide EMC a copy of Duke’s annual report, and any amendments thereto, within thirty (30) Days after the issuance/filing with the Securities and Exchange Commission of such report or amendment. EMC shall provide Duke with (a) a copy of EMC’s RUS Form 7 each Year, and any amendments to such Form 7, within thirty (30) Days after the filing of such report or amendment with RUS, and (b) the annual Debt Service Coverage Ratio and Times Interest Earned Ratio required of EMC by RUS for the Year in which the Effective Date occurs and for the two (2) immediately preceding Years.

15.7	Definitions .

“Accounting Requirements” means any system of accounts prescribed by a federal regulatory authority having jurisdiction over the applicable Party or, in the absence thereof, the requirements of generally accepted accounting principles applicable to businesses similar to that of the applicable Party; and provided, further, that EMC may use a uniform system of accounts prescribed from time-to-time by the RUS.

“CFC” means the National Rural Utilities Cooperative Finance Corporation.

“CoBank” means CoBank, ACB.

“Depreciation and Amortization Expense” shall mean an amount constituting the depreciation and amortization of EMC computed pursuant to Accounting Requirements. As used in the calculation of the Debt Service Coverage Ratio, Depreciation and Amortization Expense shall mean the amount reported on the RUS Form 7, Part A, Line 12(b), its successor, or the equivalent.

“Debt Service Coverage Ratio” means the ratio determined as follows: for any Year add (i) Patronage Capital or Margins (RUS Form 7, Part A, Line 28(b), or its successor), plus (ii) Interest Expense (RUS Form 7, Part A, Lines 15(b) and 16(b), or its successor), plus (iii) Depreciation and Amortization Expense for such year (RUS Form 7, Part A, Line 12 (b), or its successor), plus (iv) Short Term Interest Expense; and divide such total by the sum of all payments of Principal and Interest Expense during such year (RUS Form 7, Part N, Line 12(d), or its successor) plus Short Term Interest Expense; provided however, that in the event that any long-term debt has been refinanced during such Year the payments of Principal and Interest Expense required to be made during such Year on account of such long-term debt shall be based (in lieu of actual payments required to be made on such refinanced long-term debt) upon the larger of (a) an annualization of the payments required to be made with respect to the refinanced debt during the portion of such Year such refinancing debt is outstanding or (b) the payment of Principal and Interest Expense required to be made during the following Year on account of such refinancing debt.

“Equity” shall mean EMC’s equities (RUS Form 7, Part C, Line 35, its successor, or the equivalent) computed pursuant to the Accounting Requirements.

“Interest Expense” as used in the calculation of the Debt Service Coverage Ratio, Interest Expense shall mean the amount reported on the RUS Form 7, Part A, Lines 15(b) and 16(b), its successor, or the equivalent.

“Material Adverse Change” or “MAC” shall have the meaning specified in Section 15.2.

“Patronage Capital or Margins” as used in the calculation of the Debt Service Coverage Ratio or TIER, shall mean the amount currently reported in the RUS Form 7, Part A, Line 28(b), its successor, or the equivalent.

“Principal and Interest Expense” shall mean that amount of principal billed on account of total long-term debt of EMC as computed pursuant to the Accounting Requirements. As used in the calculation of the Debt Service Coverage Ratio, Principal and Interest Expense shall mean the amount currently reported on RUS Form 7, Part N, Line 12(d), or its equivalent.

“Restricted Rentals” shall mean all rentals required to be paid under finance leases and charged to income, exclusive of any amounts paid under such lease (whether or not designated therein as rental or additional rental) for maintenance or repairs, insurance, taxes, assessments, water rates or similar charges. For the purpose of this definition the term “finance lease” shall mean any lease having a rental term (including the term for which such lease may be renewed or extended at the option of the lessee) in excess of three (3) years and covering property having an initial cost in excess of two hundred fifty thousand dollars ($250,000) other than automobiles, trucks, trailers, other vehicles (including aircraft and ships), office, garage and warehouse space and office equipment (including computers).

“Short Term Interest Expense” shall mean an amount constituting the interest expense with respect to the total short-term debt of EMC, computed pursuant to Accounting Requirements, provided that all short-term debt obtained from either CFC or CoBank shall be excluded.

“Times Interest Earned Ratio” or “TIER” shall mean the ratio determined as follows for each year: add (i) Patronage Capital or Margins of EMC and (ii) Interest Expense of EMC, and divide the total so obtained by Interest Expense of EMC.

Article 16

Additional Terms

16.1 Representations Warranties and Covenants .

16.1.1 Representations and Warranties .

16.1.1.1 Mutual Representations and Warranties . Each Party represents and warrants to the other Party on the Effective Date, the Commencement Date and the first Day of any Extension Term that:

(1) There is not pending or, to its knowledge, threatened against it or any of its Affiliates any Legal Proceeding that could materially adversely affect its ability to perform its obligations under this Agreement;

(2) No event with respect to it has occurred or is continuing that would constitute an Event of Default, and no such event would occur as a result of its entering into or performing its obligations or circumstances under this Agreement;

(3) It is acting as principal for its own account and has made its own independent decision to enter into this Agreement;

(4) It has knowledge and experience in financial matters and in the electric industry that enables it to evaluate the merits and risks of this Agreement, and it is capable of assuming such risks. It is acting for its own account, has made its own independent decision to enter into this Agreement and as to whether this Agreement is appropriate and proper for it based on its own judgment, is not relying upon the advice or recommendations of the other Party in doing so, and is capable of assessing the merits of and understanding, and understands and accepts, the terms, conditions, and risks of this Agreement;

(5) It has entered into this Agreement in connection with the conduct of its business, and it has the capacity or ability to make or take delivery of all products or services referred to in this Agreement;

(6) The other Party is not acting as a fiduciary or an advisor with respect to this Agreement;

(7) It is not Bankrupt and there are no proceedings pending or being contemplated by it or, to its knowledge, threatened against it that could result in it being or becoming Bankrupt; and

(8) It is an entity subject to the procedures and substantive provisions of the United States Bankruptcy Code applicable to U.S. corporations generally.

16.1.1.2 Continuing Mutual Representations . Each Party represents, and warrants that on each of the Effective Date, the Commencement Date and throughout the Term, it will cause the following to be materially true and correct:

(1) It is duly organized, validly existing and in good standing under the Laws of the state of its incorporation;

(2) It has all requisite corporate power to own, operate and lease its properties and carry on its business as contemplated by this Agreement;

(3) Subject to the conditions provided for in Article 3, it has all lender authorizations and authorizations from Governmental Authorities necessary for it to legally perform its obligations under this Agreement;

(4) The execution, delivery and performance of this Agreement and any other documentation it is required to deliver under this Agreement are within its powers, have been duly authorized by all necessary action and do not violate any of the terms or conditions in its governing documents, any contract or other agreement to which it is a party or any Law applicable to it;

(5) The individual(s) executing and delivering this Agreement and any other documentation required to be delivered under this Agreement are duly empowered and authorized to do so at the time of such execution and delivery; and

(6) This Agreement has been duly and validly executed and delivered by such Party and constitutes such Party’s legally valid and binding obligation enforceable against it in accordance with the terms thereof, subject to any Equitable Defenses.

16.1.1.3 Additional Representations and Warranties of Duke . Duke further represents and warrants that:

(1) Subject to the conditions provided for in Article 3, Duke is fully authorized to sell the electric capacity and energy and Scheduling Agent Services it is obligated to provide under this Agreement at the rates and terms contemplated by this Agreement;

(2) Nothing in Duke’s contracts with other parties prevents Duke from fully performing its obligations under this Agreement; and

(3)(a) As of the Effective Date, Duke is a wholly owned direct subsidiary of Duke Energy Corporation, a Delaware corporation; and

(b) The provisions of the NCUC Order dated March 24, 2006, issued in Docket No. E-7, Sub. 795, the merger between Duke Energy Corporation, a North Carolina corporation, and Cinergy Corp., which closed on April 3, 2006, and the conversion of Duke Energy Corporation,

a North Carolina corporation, to Duke on April 3, 2006, did not adversely affect (1) the franchise granted to Duke by the NCUC to provide NCUC regulated electric power generation, transmission, distribution, delivery, or sales and other related services to the Duke Native Load customers located within the State of North Carolina, (2) the assets constituting Duke’s Generation System, or (3) Duke’s ability to perform its obligations under this Agreement.

16.1.1.4 Additional Representations and Warranties of EMC . EMC further represents and warrants that:

(1) Subject to the conditions provided for in Article 3, EMC is fully authorized to purchase the electric energy and capacity, and Scheduling Agent Services provided under this Agreement at the rates and terms contemplated by this Agreement; and

(2) Nothing in EMC’s contracts with other parties prevents EMC from fully performing its obligations under this Agreement.

16.1.2 Covenants .

16.1.2.1 Duke . Duke covenants that: (i) neither Duke nor any of its Affiliates or subsidiaries shall, during the Term, take any action that could reasonably be anticipated to cause Duke to lose its authority to make wholesale sales of power as contemplated under this Agreement; (ii) Duke shall not take any action during the Term that could reasonably be anticipated to cause EMC to lose its authority to purchase electric capacity and energy and Scheduling Agent Services, as contemplated by this Agreement and, as a result, EMC loses its authority to purchase electric capacity and energy and Scheduling Agent Services; and (iii) Duke shall perform its obligations under this Agreement in accordance with Prudent Utility Practice, including applicable NERC and SERC guidelines, and the Transmission Provider’s OATT.

16.1.2.2 EMC . EMC covenants that: (i) it shall not, during the Term, take any action that could reasonably be anticipated to cause it to lose its authority to purchase, or Duke to lose its authority to provide, the electric capacity and energy and Scheduling Agent Services as contemplated by this Agreement and, as a result, EMC loses its authority to purchase or Duke loses its authority to provide electric capacity and energy and Scheduling Agent Services; (ii) it shall, in the event one of the sellers under a contract pursuant to which EMC has acquired an EMC Contract Resource breaches the terms of the contract in a manner that materially affects the quality or quantity of deliveries under such contract, use Commercially Reasonable Efforts to pursue the enforcement of EMC’s contract rights; (iii) electric energy delivered by MSCG under the PPA qualifies as Firm Energy; and (iv) EMC shall perform its obligations under this Agreement in accordance with Prudent Utility Practice, including applicable NERC and SERC guidelines, and the Transmission Provider’s OATT.

16.2 Assignment .

16.2.1 General .

16.2.1.1 Duke shall not assign this Agreement or its rights hereunder without the prior written consent of EMC, which consent shall not be unreasonably withheld; provided, however, that Duke may, without the consent of EMC, (a) transfer, sell, pledge, encumber or assign this Agreement or the accounts, revenues or proceeds hereof in connection with any financing or other financial arrangements (without relieving itself from liability hereunder), or (b) transfer or assign this Agreement to any person or entity succeeding to all or substantially all of Duke’s Generation System, and whose unsecured, senior long-term debt obligations not supported by third party credit enhancements are rated BBB- or higher by S&P or Baa3 or higher by Moody’s (or, in the alternative, whose obligations under this Agreement are guaranteed by a guarantor that meets the foregoing credit standards, provided that the form of the guaranty shall be reasonably satisfactory to EMC). Duke shall be relieved of all liability under this Agreement arising on and after the effective date of an assignment that satisfies the requirements of subpart (b) above.

16.2.1.2 EMC shall not assign this Agreement or its rights hereunder without the prior written consent of Duke, which consent shall not be unreasonably withheld; provided, however, that EMC may, without the consent of Duke, (a) transfer, sell, pledge, encumber or assign this Agreement or the accounts, revenues or proceeds hereof in connection with any financing or other financial arrangements (without relieving itself from liability hereunder), or (b) transfer or assign this Agreement to any person or entity (A) succeeding to substantially the same Service Area and retail load as the EMC Native Load and to EMC’s rights under the EMC Contract Resources, and (B):

(i) if the transferee or assignee is an electric membership corporation organized under Article 2 Chapter 117 of the North Carolina General Statutes, it meets both the then-current Debt Service Coverage Ratio required of EMC by RUS, as determined by averaging the two (2) highest annual ratios during the most recent three (3) years, and the then-current Times Interest Earned Ratio required of EMC by RUS, as determined by averaging the two (2) highest annual ratios during the most recent three (3) years, or

(ii) if the transferee or assignee is not an electric membership corporation organized under Article 2 Chapter 117 of the North Carolina General Statutes, then its unsecured, senior long-term debt obligations not supported by third party credit enhancements are rated BBB- or higher by S&P or Baa3 or higher by Moody’s (or, in the alternative, whose obligations under this Agreement are guaranteed by a guarantor that meets the foregoing credit standards, provided that the form of the guaranty shall be reasonably satisfactory to Duke). EMC shall be relieved of all liability under this Agreement arising on and after the effective date of an assignment that satisfies the requirements of this subpart (B)(ii).

16.2.1.3 This Agreement shall be binding upon and inure to the benefit of the permitted successors and permitted assigns of the Parties. Any assignment made without a consent required hereunder shall be void and of no force or effect as against the non-consenting Party. No sale, assignment, transfer, or other disposition permitted by this Agreement shall affect, release, or discharge any Party from its rights or obligations under this Agreement, except as may be expressly provided by this Agreement or by written agreement of the Parties.

16.2.2 Assignment For Security . Notwithstanding any other provision of this Agreement, a Party, without the other Party’s consent but, if such assigning Party is then a borrower of the RUS, only with the consent of the Administrator, may assign, transfer, mortgage or pledge its interest in this Agreement as security (an “Assignment for Security”) for any obligation secured by any indenture, mortgage, or similar lien on its system assets without limitation on the right of the secured party to further assign this Agreement, including the assignment to create a security interest for the benefit of the Government, acting through the Administrator, or for the benefit of any third party.

16.2.3 Assignment By Administrator . After any Assignment for Security to the Administrator or other secured party (including any indenture trustee under any indenture securing the obligations of the Party), the Administrator or other secured party, without the approval of the other Party, may (i) cause the interest in this Agreement of the Party who made the Assignment for Security to be sold, assigned, transferred or otherwise disposed of to a third party pursuant to the terms governing such Assignment for Security, or (ii) if the Administrator or other secured party first acquires this Agreement, sell, assign, transfer or otherwise dispose of this Agreement to a third party; provided, however, that in either case the Party who made the Assignment for Security is in default of its obligations to the Administrator or other secured party that are secured by such security interest.

16.3	Liability and Indemnification .

16.3.1 Indemnity . Each Party shall indemnify, defend, and hold harmless the other Party from and against:

(1) Any Claims arising from or out of any event, circumstance, act, or incident first occurring or existing during the period when control and title to any electric energy is vested in such Party as provided in Section 4.5, and

(2) Any Governmental Charges for which such Party is responsible under Section 16.7.2.

Notwithstanding the foregoing, no Party will be required to indemnify, defend, or hold harmless any other Party from any losses or Claims under this Section 16.3.1 to the extent that such loss or Claim was caused by the other Party’s gross negligence or willful misconduct.

16.3.2 Liability Limitations .

16.3.2.1 Limitation of Remedies . THE PARTIES CONFIRM THAT THE EXPRESS REMEDIES AND MEASURES OF DAMAGES PROVIDED IN THIS AGREEMENT SATISFY THE ESSENTIAL PURPOSES HEREOF. FOR BREACH OF ANY PROVISION FOR WHICH AN EXPRESS REMEDY OR MEASURE OF DAMAGES IS PROVIDED, SUCH EXPRESS REMEDY OR MEASURE OF DAMAGES SHALL BE THE SOLE AND EXCLUSIVE REMEDY, THE RESPONSIBLE PARTY’S LIABILITY SHALL BE LIMITED AS SET FORTH IN SUCH PROVISION AND ALL OTHER REMEDIES OR

DAMAGES AT LAW OR IN EQUITY ARE WAIVED REGARDLESS OF THE FAULT, NEGLIGENCE, OR STRICT LIABILITY OF THE PARTY WHOSE LIABILITY IS RELEASED OR LIMITED THEREBY.

IF NO REMEDY OR MEASURE OF DAMAGES IS EXPRESSLY HEREIN PROVIDED, AND EXCEPT AS OTHERWISE EXPLICITLY PROVIDED IN SECTION 16.6.4, THE RESPONSIBLE PARTY’S LIABILITY SHALL BE LIMITED TO DIRECT ACTUAL DAMAGES (INCLUDING INTEREST AS PERMITTED BY APPLICABLE LAW) ONLY, SUCH DIRECT ACTUAL DAMAGES SHALL BE THE SOLE AND EXCLUSIVE REMEDY AND ALL OTHER REMEDIES OR DAMAGES AT LAW OR IN EQUITY ARE WAIVED (EXCEPT AS PROVIDED IN SECTION 16.29).

UNLESS EXPRESSLY HEREIN PROVIDED, (INCLUDING AS PROVIDED IN SECTION 16.6.4) NO PARTY SHALL BE LIABLE FOR CONSEQUENTIAL, INCIDENTAL, PUNITIVE, MULTIPLE, EXEMPLARY, OR INDIRECT DAMAGES, LOST PROFITS, OR OTHER BUSINESS INTERRUPTION DAMAGES, BY STATUTE, IN TORT OR IN CONTRACT UNDER ANY INDEMNITY PROVISION OR OTHERWISE. IT IS THE INTENT OF THE PARTIES THAT THE LIMITATIONS HEREIN IMPOSED ON REMEDIES AND THE MEASURE OF DAMAGES BE WITHOUT REGARD TO THE CAUSE OR CAUSES RELATED THERETO, INCLUDING THE NEGLIGENCE OF ANY PARTY, WHETHER SUCH NEGLIGENCE BE SOLE, JOINT, OR CONCURRENT, OR ACTIVE OR PASSIVE.

16.3.2.2 Disclaimer . EXCEPT AS EXPRESSLY SET FORTH IN THIS AGREEMENT, EACH PARTY , WITH RESPECT TO THE SUPPLY OF ELECTRIC ENERGY AND CAPACITY TO THE OTHER , EXPRESSLY NEGATES ANY OTHER REPRESENTATION OR WARRANTY, WRITTEN OR ORAL, EXPRESS OR IMPLIED, INCLUDING, WITHOUT LIMITATION, ANY REPRESENTATION OR WARRANTY WITH RESPECT TO CONFORMITY TO MODELS OR SAMPLES, MERCHANTABILITY, OR FITNESS FOR ANY PARTICULAR PURPOSE.

16.3.2.3 Duty to Mitigate . Each Party agrees that is has a duty to mitigate damages, and each covenants that it shall use commercially reasonable efforts to minimize any damages it may incur as a result of the other Party’s performance or nonperformance of this Agreement.

16.4 Force Majeure . Unless otherwise provided by this Agreement, the term “Force Majeure” means an event or circumstance that: (i) prevents the Party claiming to be affected by it (the “Claiming Party”) from performing its obligations in whole or in part under this Agreement; (ii) is not within the reasonable control of the Claiming Party, or the result of the negligence of the Claiming Party, and (iii) by the exercise of due diligence, the Claiming Party is unable to overcome in a commercially reasonable manner, and, without limiting the scope of the definition, includes acts of God, or the public enemy, or insurrection, riot, acts of terrorism, civil disturbance or disorder, strikes, fire, earthquakes, floods, storms or other natural disasters, or actions or restraints by court order or Governmental Authority or arbitration award (so long as the Claiming Party has not sought or has opposed, to the extent reasonable, such actions or restraints). To the extent that the Claiming Party is prevented by Force Majeure from carrying

out, in whole or part, its obligations hereunder and such Party gives notice and details of the Force Majeure to the other Party (the “Non-Claiming Party”) as soon as practicable, then the Claiming Party shall be excused from the performance of its obligations other than the obligation to make payments then due or becoming due in respect to performance prior to the Force Majeure, except as otherwise explicitly provided in this Agreement. The Claiming Party shall remedy the Force Majeure event with all reasonable dispatch. The Non-Claiming Party shall not be required to perform or resume performance of its obligations to the Claiming Party corresponding to the obligations of the Claiming Party excused by Force Majeure during the period that such Force Majeure remains in effect. Duke shall not adversely distinguish between EMC’s Native Load and Duke’s Native Load in claiming an event of Force Majeure.

16.5 Events of Default and Remedies .

16.5.1 Events of Default . For the purposes of this Agreement, an “Event of Default” means, with respect to a Party (a “Defaulting Party”), the occurrence of any of the following:

(1) The failure to make, when due, any payment or reimbursement required by this Agreement (including any amounts to be credited by one Party to the other Party) or to post or maintain collateral required by this Agreement, if such failure is not remedied within three (3) Business Days after receipt of written notice of such failure is given to the Defaulting Party by the other Party (“Non-Defaulting Party”). For the purposes of this Section 16.5.1(1), withholding one half (1/2) of a Disputed Amount in accordance with Section 13.5 shall not constitute failure to make, when due, a payment;

(2) Any representation or warranty made by such Party herein is false or misleading in any material respect when made or when deemed made or repeated;

(3) The failure to perform any material covenant or material obligation set forth in this Agreement (except to the extent constituting a separate Event of Default under this Section 16.5), if such failure is not remedied within three (3) Business Days after receipt of written notice thereof to the Defaulting Party, provided, that a Party’s failure to perform its obligations under Section 16.1.2.1(iii) or Section 16.1.2.2(iv) shall not in and of itself constitute a material failure to perform a material covenant or material obligation unless such failure, in the case of Duke, results in a substantial and continuing degradation in reliability of service hereunder or, in the case of EMC, results in a substantial and continuing degradation in performance hereunder;

(4) Such Party becomes Bankrupt;

(5) The loss of any authorization from Governmental Authorities necessary to perform its obligations hereunder in accordance with the terms of this Agreement;

(6) Such Party consolidates or amalgamates with, or merges with or into, or transfers all or substantially all of its assets to, another entity and, at the

time of such consolidation, amalgamation, merger, or transfer, the resulting, surviving, or transferee entity fails to assume all of the obligations of such Party under this Agreement to which it or its predecessor was a party by operation of law or pursuant to an agreement reasonably satisfactory to the other Party;

(7) The occurrence and continuation of a default, event of default, or other similar condition or event that under one or more agreements or instruments, individually or collectively, relating to indebtedness for borrowed money in an aggregate amount of not less than nine million dollars ($9,000,000) in the case of EMC or one hundred fifty million dollars ($150,000,000) in the case of Duke, that results in the Party’s indebtedness under such agreements or instruments to become immediately due and payable; and

(8) With respect to such Party’s guarantor, if any:

(a)

if any representation or warranty made by a guarantor in connection with this Agreement is false or misleading in any material respect when made or when deemed made or repeated;

(b)

the failure of a guarantor to make any payment required or to perform any other material covenant or obligation in any guaranty made in connection with this Agreement and such failure shall not be remedied within three (3) Business Days after written notice;

(c)

a guarantor becomes Bankrupt;

(d)

the failure of a guarantor’s guaranty to be in full force and effect for purposes of this Agreement (other than in accordance with its terms); or

(e)

a guarantor shall repudiate, disaffirm, disclaim, or reject, in whole or in part, or challenge the validity of any guaranty.

16.5.2 Notice of Event of Default . In the event a Party becomes aware of any event or circumstance that constitutes an Event of Default, such Party shall promptly notify the other Party in writing and by telephone.

16.5.3 Effect of Event of Default . If at any time an Event of Default with respect to a Defaulting Party has occurred and is continuing, the other Party (the “Non-Defaulting Party”) may do one or more of the following:

(1) If an Event of Default under Section 16.5.1(1) persists for ten (10) Days or longer, terminate this Agreement in accordance with the notification required pursuant to Sections 2.3.2.1 and 2.3.3 of this Agreement; or

(2) If an Event of Default (other than an Event of Default under Section 16.5.1(1)) persists for sixty (60) Days or longer, terminate this Agreement in accordance with Sections 2.3.2.1 and 2.3.3 of this Agreement, provided, however, that if the Defaulting Party is diligently pursuing cure, but such Event of Default is not capable of being cured within sixty (60) Days, then the period for the Defaulting Party to cure such Event of Default shall be extended from sixty (60) Days to one hundred eighty (180) Days before the Non-Defaulting Party may exercise its right to terminate this Agreement pursuant to this Section 16.5.3(2).

16.5.4 Enforcement of Remedies . The Non-Defaulting Party may exercise any rights or remedies available at law or equity, subject to the provisions of Article 14 and Sections 15.5 and 16.3 of this Agreement. No delay or failure on the part of a Non-Defaulting Party to exercise any right or remedy to which it may become entitled on account of an Event of Default shall constitute an abandonment of any such right, and the Non-Defaulting Party shall be entitled to exercise such right or remedy at any time during the continuance of an Event of Default notwithstanding any delay in enforcing such right. No waiver of any Event of Default shall constitute a waiver of any later Event of Default; all such waivers shall be in writing and shall in no circumstance be deemed effective unless such waiver is made in writing. All of the remedies and other provisions of this Section 16.5 shall be without prejudice and in addition to any right of setoff, recoupment, combination of accounts, lien, or other right to which any Party or any of its Affiliates is at any time otherwise entitled, whether by operation of law or in equity, under contract, or otherwise.

16.6	Confidential Information .

16.6.1 Prior Confidentiality Agreements Unaffected . Any preexisting confidentiality agreements entered into by the Parties pertaining to the negotiation and development of this Agreement shall survive by their terms and shall not be considered modified by this Agreement.

16.6.2 Authorized Disclosure . Each Party agrees to preserve, to the maximum extent permitted by Law, the confidentiality of Confidential Information supplied to it by the other Party either during the negotiations leading to this Agreement or during the course of implementing, performing or winding up this Agreement. A Party may disclose Confidential Information received from the other Party to the receiving Party’s Affiliates, auditors, attorneys, consultants, advisors, persons providing financing to the receiving Party, other entities in the EMC Group that have entered into substantially similar agreements, and to other third parties as may be necessary for the receiving Party to perform its obligations under this Agreement, provided that any such persons agree in writing to be bound by the confidentiality provisions of this Agreement. Notwithstanding anything contained in this Section 16.6, Confidential Information may be disclosed to any Governmental Authority requiring such Confidential Information, provided that: (i) such Confidential Information is submitted under applicable provisions, if any, for confidential treatment by such Governmental Authority; (ii) prior to such disclosure, the Party who supplied the information is given notice of the disclosure requirement (if time permits and the other Party’s counsel determines that such notice is permitted by Law) so that it may take at its own risk and expense whatever action it deems appropriate, including intervention in any proceeding and the seeking of an injunction to prohibit such disclosure; and (iii) the Party subject to the Governmental Authority endeavors to protect the confidentiality of

any Confidential Information to the extent reasonable under the circumstances and to use its good faith efforts to prevent the further disclosure of any Confidential Information provided to any Governmental Authority. The Parties recognize that Duke is required to file periodic reports with FERC that disclose certain price, quantity, and related data, and such filings shall not be deemed a violation of this section.

16.6.3 Survival of Confidentiality Obligations . Confidential Information received from the other Party shall be kept confidential in accordance with the terms of this Agreement for at least five (5) Years after the termination of this Agreement.

16.6.4 Right to Remedies . In the event of an unauthorized disclosure to a third party, the limitations on remedies contained in Section 16.3.2.1 shall not apply, and, in the event of a breach, Parties shall not have an adequate remedy at law and accordingly shall, in addition to any other available legal or equitable remedies, be entitled to an injunction against such breach without any requirement to post a bond as a condition of such relief.

16.7 Governmental Liabilities .

16.7.1 Minimization of Tax Liability . Each Party shall use reasonable efforts to implement the provisions of and to administer this Agreement in accordance with the intent of the Parties to minimize all taxes, so long as neither Party is materially adversely affected by such efforts.

16.7.2 Governmental Charges .

16.7.2.1 With respect to sales of electric energy made by Duke to EMC, Duke shall pay or cause to be paid all Governmental Charges imposed by any Government Authority on or with respect to such sales of electric energy to the extent such Governmental Charges arise prior to the Delivery Point. EMC shall pay or cause to be paid all Governmental Charges on or with respect to such sale of electric energy to the extent such Governmental Charges arise after the Delivery Point (other than ad valorem, franchise, or income taxes that are related to the sale of such product and are, therefore, the responsibility of Duke).

16.7.2.2 With respect to sales of electric energy by EMC to Duke, EMC shall pay or cause to be paid all Governmental Charges on or with respect to the sale of the electric energy to Duke.

16.7.2.3 In the event a Party is required by Law to remit or pay Governmental Charges that are the other Party’s responsibility hereunder, the Party ultimately liable for the Governmental Charge shall promptly reimburse the remitting Party for such Governmental Charges; provided further that tax liabilities may be netted pursuant to Section 13.4 of this Agreement. Nothing will obligate or cause a Party to pay or be liable to pay any Governmental Charges for which it is exempt under the Law.

16.7.3 Records . If with respect to either Party, any purchase or sale of electric energy is exempt from Governmental Charges it shall, upon written request of the other Party, provide a certificate of exemption or other reasonably satisfactory evidence of exemption, and shall use reasonable efforts to obtain and cooperate with obtaining any exemption from or reduction of any Governmental Charges.

16.7.4 Cost of Obtaining FERC Approval . The Parties agree that all fees assessed by FERC, or expenses incurred in obtaining the approval of FERC for this Agreement, shall be the sole responsibility of Duke.

16.7.5 Cost of Obtaining RUS Approval . The Parties agree that all fees assessed by the RUS, or expenses incurred in obtaining the approval of RUS for this Agreement, shall be the sole responsibility of EMC.

16.8 Choice of Law . The validity, interpretation and performance of this Agreement and the rights and duties of the Parties arising out of this Agreement shall be governed by and construed, enforced, and performed in accordance with the Laws of the State of North Carolina. No principle, doctrine, or rule of conflicts of law shall modify or alter the applicability of the Laws of the State of North Carolina to this Agreement.

16.9 Survival of Obligations . Upon the termination of the Parties’ delivery, sale, purchase, and related service obligations under this Agreement, any monies, penalties or other charges due and owing under this Agreement shall be paid, any corrections or adjustments to payments previously made shall be determined, and any refunds due shall be made, as soon as practicable but no later than sixty (60) Days after such termination. All indemnity and confidentiality obligations and audit rights shall survive the termination of this Agreement in accordance with their respective terms. Upon the effective date of any termination of this Agreement, each Party’s obligations provided for in this Agreement will survive termination and remain in effect solely for the purpose of complying with the provisions of this Section 16.9; OTHERWISE, AS PROVIDED IN ARTICLE 2, TERMINATION OF THIS AGREEMENT IS ABSOLUTE, AND NO OTHER OBLIGATIONS, DUTIES, OR RIGHTS WHATSOEVER ARISING UNDER THIS AGREEMENT SHALL REMAIN IN EFFECT FOLLOWING THE TERMINATION OF THIS AGREEMENT .

16.10 Entire Agreement . This Agreement, and the Schedules and Attachments attached hereto, constitute the entire and integrated agreement between the Parties relating to the rates, terms, and conditions set out in this Agreement as of the Effective Date . This Agreement supersedes all prior agreements (other than the Confidentiality Agreement which became fully executed on November 22, 2004) whether oral or written, related to the subject matter of this Agreement. The terms of this Agreement, including any Schedules and Attachments attached hereto, are controlling, and no parol or extrinsic evidence, including but not limited prior drafts or projections of future costs or rates, shall be used to vary, contradict, or interpret the express rates, terms, and conditions of this Agreement or as a basis for challenging the justness and reasonableness of any rate, term, or condition of this Agreement.

16.11 Cost Projections .

16.11.1 Duke Cost Projections . Duke makes no warranties or representations whatsoever concerning any cost or rate projections that it provided in connection with the negotiations leading up to the execution of this Agreement and any such projections provided by

Duke under Section 16.26 of this Agreement. EMC assumes the risk of reliance on any projected costs or rates provided by Duke in connection with the negotiations leading up to the execution of this Agreement or any projections provided by Duke under Section 16.26. Any differences between projected costs or rates provided by Duke and actual costs or rates will not limit or in any way affect the rates, terms, or conditions of this Agreement or any of the Parties’ rights and obligations hereunder.

16.11.2 EMC Cost Projections . EMC makes no warranties or representations whatsoever concerning any cost or rate projections that it provided in connection with the negotiations leading up to the execution of this Agreement and any such projections provided by EMC during the Term. Duke assumes the risk of reliance on any projected costs or rates provided by EMC in connection with the negotiations leading up to the execution of this Agreement or any projections provided by EMC during the Term. Any differences between projected costs or rates provided by EMC and actual costs or rates will not limit or in any way affect the rates, terms, or conditions of this Agreement or any of the Parties’ rights and obligations hereunder.

16.12 Unique Agreement . This Agreement shall not establish any precedent for any other services, or be relied upon by either Party for any purpose other than for the services and payments provided herein.

16.13 No Transfer of Rights . Except as explicitly provided herein, nothing in this Agreement shall be construed to transfer any rights or obligations that either Party has under any other agreement to the other Party.

16.14 No Partnership . The Parties are independent contractors. Nothing in this Agreement shall ever be deemed to create or constitute a partnership, joint venture, or association between the Parties, or to impose a trust or partnership duty, obligation, or liability on or with regard to either of the Parties.

16.15 Third Parties . The provisions of this Agreement shall not impart rights enforceable by any person or entity not a Party or not a permitted successor or assignee of a Party bound by this Agreement. This Agreement shall not be construed to create any third party beneficiary rights of any sort.

16.16 Waiver . No waiver of all or any part of this Agreement shall be valid unless it (a) is reduced to writing, (b) expressly states that the Parties agree to such waiver, and (c) is signed by the Parties. Except as specifically set forth herein, neither Duke’s nor EMC’s failure to enforce any provision or provisions of this Agreement shall in any way be construed as a waiver of any such provision or provisions as to any future violation thereof, nor prevent it from enforcing each and every provision of this Agreement at such time or at any time thereafter. The waiver by either Duke or EMC of any right or remedy shall not constitute a waiver of its right to assert said right or remedy, at any time thereafter, or any other rights or remedies available to it at the time of or any time after such waiver.

16.17 Time of Essence . Time is of the essence for, in, and throughout this Agreement.

16.18 Headings . The descriptive headings of the various Articles and Sections of this Agreement (or any Schedules and Attachments attached hereto) have been inserted for convenience of reference only and in no way shall be deemed to modify or restrict any of the terms or provisions hereof.

16.19 Severability . Wherever possible, each provision of this Agreement (including any Schedules or Attachments attached hereto) shall be interpreted in a manner as to be effective and valid under applicable Law, but if any provision contained herein shall be found or ruled to be invalid, illegal, or unenforceable in any respect and for any reason, such provision shall be ineffective to the extent, but only to the extent, of such invalidity, illegality, or unenforceable without invalidating the remainder of the provision or any provision of this Agreement, and in such event, the Parties shall attempt to negotiate amendments to this Agreement that would permit each Party to realize the equivalent value of the economic bargain contemplated by this Agreement absent such finding or ruling.

16.20 Counterparts . This Agreement may be executed in any number of counterparts, each of which shall be an original, but all of which together shall constitute one and the same instrument.

16.21 No Public Announcement . The Parties agree that no press release or public announcement concerning the transaction contemplated by this Agreement will be made unless mutually agreed to by the Parties in writing; provided, however, such mutual agreement will not be required if:

(a) The disclosing Party determines that disclosure is reasonably necessary to (i) comply with applicable Laws of a Governmental Authority having jurisdiction; or (ii) obtain financing for the transaction contemplated by this Agreement; or

(b) the disclosure is limited to the following information: (i) the names of the Parties; (ii) the type of service being provided; (iii) the Term; and (iv) the total load being served.

The disclosing Party shall provide the other Party with written notice of such disclosure at least five (5) Business Days prior to such disclosure.

16.22 Notices . Unless otherwise provided in this Agreement, any notice, consent, or other communication required to be made under this Agreement shall be in writing and shall be delivered in person, by certified mail (postage prepaid, return receipt requested), or by nationally recognized overnight courier (charges prepaid), in each case properly addressed to such Party as shown below. Any Party may from time to time change its address, designee or contact information for the purposes of notices, consents, or other communications to that Party by a similar notice specifying a new address, but no such change shall become effective until it is actually received by the Party to be charged with its contents. All notices, consents, or other communications required or permitted under this Agreement that are addressed as provided in this Section 16.22 shall be deemed to have been given upon delivery if delivered in person, or upon deposit if delivered by overnight courier or certified mail.

Duke :

Duke Power Company LLC

526 South Church Street

Charlotte, N.C. 28202

Attn: VP – Business Development and Origination

Phone: (704) 382-3114

Fax: (704) 382-4014

With a copy to:

Duke Power Company LLC

526 South Church Street

Charlotte, N.C. 28202

Attn: General Counsel

EMC :

Piedmont Electric Membership Corporation

2500 N.C. 86 South

Post Office Drawer 1179

Hillsborough, North Carolina 27278

Attn: R.G. Brecheisen, President and Chief Executive Officer

Phone: 919-732-2123

Fax: 919-644-1030

The Parties may agree on alternative methods of giving operational and scheduling notices, consistent with the requirements of the applicable Transmission Providers and/or generation scheduling providers.

16.23 No Dedication of the System . No undertaking by either Party to the other Party under any provision of this Agreement shall constitute the dedication of the system, or any portion thereof, of either Party to the public or to the other Party, and it is understood and agreed that any such undertaking by either of the Parties shall cease after the termination date of this Agreement. The sale by Duke to EMC of electric capacity and energy under this Agreement does not constitute a sale, lease, transfer, or conveyance of any kind of ownership interest in or to any of Duke’s facilities of any kind.

16.24 Stranded Costs .

16.24.1 If a Party or any of its Affiliates becomes entitled to receive compensation associated with stranded generation, transmission, distribution or other assets or costs, the other Party shall have no claim or entitlement to any such compensation.

16.24.2 Neither EMC nor Duke shall have the obligation or liability to the other Party for the payment of any amounts authorized by statute or ordered or approved by a Governmental Authority and that are attributable to or in any way arising from stranded

generation, transmission, distribution, or other assets or costs or any liability associated therewith, whether such amounts are characterized as competitive transition charges, wire charges, or other costs or charges, provided that nothing herein shall limit the damages that may otherwise be recovered for an Event of Default. An order on stranded costs shall not be deemed a Material Adverse Ruling.

16.25 Electric Peak Load and Energy Information to be provided by EMC . Prior to October 1, 2006, and each October 1 thereafter during the Term, EMC shall provide Duke with forecast projections of (a) EMC’s Monthly electric peak load and electric energy requirements for the following Year and (b) EMC’s annual electric peak load and electric energy requirements for the following ten (10) years, to the extent EMC has such information available, except that, after a Notice of Termination has been given, EMC shall not be obligated to provide such information for the period after the termination date. To the extent such information is provided in a report to the RUS that is publicly available, EMC may satisfy this requirement by providing a copy of such report to Duke.

16.26 Demand and Energy Charge and Rate Information to be Provided by Duke . Prior to December 1, 2006, and each December 1 thereafter during the Term, Duke shall provide EMC with forecast projections of (a) the annual electric capacity and energy rates under Sections 7.2 or Section 7.3 (as applicable) for the following year, (b) Monthly demand and electric energy charges under Section 7.2 or Section 7.3 (as applicable) for the following year, and (c) annual demand and electric energy charges under Sections 7.2 or Section 7.3 (as applicable) for the lesser of the remainder of the Term or the following ten (10) Years, except that, after a Notice of Termination has been given, Duke shall not be obligated to provide such information for the period after the termination date.

16.27 Further Assurances . If either Party determines in its reasonable discretion that any further instruments, assurances, or other things are necessary or desirable to carry out the terms of this Agreement, the other Party shall execute and deliver all such instruments or assurances, and do all things reasonably necessary or desirable to carry out the terms of this Agreement.

16.28 Applicable Laws and Regulations . This Agreement is made subject to all existing and future applicable Laws and to all existing and future promulgated orders or other duly authorized actions of Governmental Authorities having jurisdiction over the matters set forth in this Agreement.

16.29 Equitable Relief . Nothing in this Agreement shall be construed to limit the injunctive or equitable powers of a court of competent jurisdiction.

16.30 PURPA Assistance . Duke shall provide assistance to EMC, as EMC reasonably requests, to support EMC’s compliance with the generation efficiency and fuel diversity standards under PURPA.

16.31 SERC and NERC Data Reporting and Compliance Assistance . Duke shall report EMC’s actual load, forecasted load (as provided by EMC to Duke), and resource information to SERC and NERC and their successors, in a manner similar to the manner in which Duke reports such information for other wholesale full or partial requirements customers with service as firm as Duke’s Native Load. In addition, Duke shall provide assistance and consultation to EMC, to the extent agreed to by the Parties, to support EMC’s compliance with such organizations’ data reporting requirements.

IN WITNESS WHEREOF, the Parties have caused this Agreement to be executed by their duly authorized officers and copies delivered to each Party.

PIEDMONT ELECTRIC MEMBERSHIP CORPORATION


By:
Name:		Randolph G. Brecheisen
Title:		President and Chief Executive Officer

DUKE POWER COMPANY LLC d/b/a Duke Energy Carolinas, LLC

By:
Name:		Ellen T. Ruff
Title:		President

Schedule 1

Annual Production Capacity and Energy Rates

Schedule 1 Methodology:

This formula sets forth the method that Duke will use to determine its annual Demand Rates, Fuel Rates, and Variable O&M Rates (collectively, “Rates”) for use during the System Average Pricing Option Period, if any, and during the period January 1, 2011 through the termination of this Agreement. The Rates will be annual formula rate calculations. The Rates shall initially be estimated for the period January 1 - December 31 of the Year in which such Rates are first applicable, and shall be estimated continuing thereafter for successive twelve month periods. Beginning July 1 of the Year in which such Rates are first applicable, and each July 1 thereafter, the Rates will be trued-up based on actual costs and loads for the most recent calendar Year, using the formula rates set forth below. The calculations will be based on Duke’s FERC Form 1 data and Duke’s company records. The true-up will include interest on any refunds or surcharges calculated in accordance with the methodology set forth in 18 C.F.R. § 35.19a or its successor. The formulas for the Rates were designed to include all costs incurred by Duke to own, operate and maintain Duke’s Generation System. The formulas for the Rates may only be amended by the mutual agreement of the Parties or pursuant to Section 12.3 of the Agreement. Disallowance or any other treatment of any such costs by the NCUC or any other Governmental Authority other than FERC will not have any effect on the inclusion of such costs in the formulas for the Rates as set forth below.

I.	Definitions

Capitalized terms not otherwise defined in the Agreement and as used in this formula have the following definitions:

Allocation Factors

Production Wages and Salaries Allocation Factor shall equal the ratio of Duke’s production-related direct wages and salaries to Duke’s total direct wages and salaries excluding administrative and general wages and salaries.

Production Plant Allocation Factor shall equal the ratio of the sum of Duke’s investments in Production Plant plus Production Related General Plant plus Production Related Intangible Plant to investment in Total Plant in Service.

Terms

Accumulated Deferred Income Taxes shall equal the net of Duke’s electric deferred tax balances as recorded in FERC Account Nos. 281-283 and Duke’s electric deferred tax balance as recorded in FERC Account No. 190.

Administrative and General Expense shall equal Duke’s expenses as recorded in FERC Account Nos. 920-935 excluding FERC Account Nos. 924, 928 and 930.1, and less EPRI dues as recorded in FERC Account No. 930.2.

Contra AFUDC shall equal the reduction in amount of AFUDC recorded in FERC Account No. 107 due to recovery of construction period financing costs from customers resulting from inclusion of construction work in progress in rate base in any of Duke Power’s retail or wholesale rate jurisdictions.

Demand Rate means the Demand Rate calculated in Part II below.

Depreciation Expense for Production Plant shall equal Duke’s production expense as recorded in FERC Account No. 403 plus an adjustment to increase depreciation expense to eliminate any reduction in depreciable base for Contra AFUDC related to production plant construction work in progress included in rate base.

Duke’s Average Peak Hour Load for a year, with respect to the System Average Pricing Option Period, if any, shall equal the average of the twenty highest hourly (integrated sixty minute) Duke Schedule 1 Demands during July and August of the year; and with respect to the period beginning January 1, 2011, and continuing through the termination of the Agreement, shall equal the average of the twenty highest hourly (integrated sixty minute) Duke Schedule 1 Demands during the Annual Planning Period of the year.

Duke Schedule 1 Demands means Duke’s Native Load demands: (i) compensated for losses to the point at which power is available for transmission, (ii) excluding (a) non-requirements wholesale sales, as listed in Duke’s FERC Form 1, and (b) wholesale sales with a duration of one year or less, (iii) served by Duke’s Generation System the cost of which is included in Schedule 1.

FAS 109 Regulatory Assets and Liabilities shall equal the net of Duke’s FAS 109 balance as recorded in FERC Account No. 182.3 and any Duke FAS 109 balance as recorded in FERC Account No. 254.

FAS 106 Regulatory Assets and Liabilities shall equal the net of Duke’s FAS 106 balance as recorded in FERC Account No. 182.3 and any Duke FAS 106 balance as recorded in FERC Account No. 254.

General Plant shall equal Duke’s gross plant balance as recorded in FERC Balance Sheet Account No. 101, FERC Electric Plant Account Nos. 389-399, and amounts in FERC Balance Sheet Account Nos. 102 and 106 tentatively classified to FERC Electric Plant Account Nos. 389-399, plus an adjustment to add Contra AFUDC related to general plant construction work in progress included in rate base.

General Plant Depreciation Expense shall equal Duke’s general plant expenses as recorded in FERC Account No. 403 plus an adjustment to increase depreciation expense to eliminate any reduction in depreciable base for Contra AFUDC related to general plant construction work in progress included in rate base.

General Plant Depreciation Reserve shall equal Duke’s general plant reserve balance as recorded in FERC Account No. 108 plus an adjustment to increase the reserve to equal accumulated depreciation for depreciable base without reduction for Contra AFUDC related to production plant construction work in progress included in rate base.

General Tax Expense shall equal Duke’s expenses as recorded in FERC Account No. 408.1.

Intangible Plant shall equal Duke’s gross plant balance as recorded in FERC Balance Sheet Account No.101, FERC Electric Plant Account Nos. 301-303, and amounts in FERC Balance Sheet Account Nos. 102 and 106 tentatively classified to FERC Electric Plant Account Nos. 301-303, plus an adjustment to add Contra AFUDC related to intangible plant construction work in progress included in rate base.

Intangible Plant Amortization Expense shall equal Duke’s intangible plant expenses as recorded in FERC Account No. 404 plus an adjustment to increase depreciation expense to eliminate any reduction in depreciable base for Contra AFUDC related to intangible plant construction work in progress included in rate base.

Intangible Plant Amortization Reserve shall equal Duke’s intangible plant reserve balance as recorded in FERC Account No. 111 plus an adjustment to increase the reserve to equal accumulated depreciation for depreciable base without reduction for Contra AFUDC related to intangible plant construction work in progress in rate base.

Net Asset Retirement Cost shall equal Duke’s asset retirement costs recorded in FERC Account No. 101, less the associated accumulated depreciation included in FERC Account No. 108.

Other Amortization shall equal Duke’s amortization expense recorded in FERC Account Nos. 406 and 407 that is related to production plant.

Other Regulatory Assets/Liabilities shall equal the net of Duke’s regulatory assets and liabilities in FERC Account Nos. 182, 228 and 254, excluding FAS 109 Regulatory Assets and FAS 106 Regulatory Assets, that are production related.

Payroll Taxes shall equal those payroll tax expenses as recorded in Duke Power’s FERC Account No. 408.1.

Plant Held for Future Use shall equal Duke’s balance in FERC Account No. 105.

Prepayments shall equal Duke’s prepayment balance as recorded in FERC Account No. 165.

Property Insurance shall equal Duke’s expenses as recorded in FERC Account No. 924.

Production Related Amortization of Investment Tax Credits shall equal Duke’s credits as recorded in FERC Account No. 411.4 multiplied by the Production Plant Allocation Factor.

Production Depreciation Reserve shall equal Duke’s production reserve balance as recorded in FERC Account No. 108 plus an adjustment to increase the reserve to equal accumulated depreciation for depreciable base without reduction for Contra AFUDC related to production plant construction work in progress included in rate base.

Production Operation and Maintenance (O&M) Expense shall equal Duke’s expenses as recorded in FERC Account Nos. 500-557.

Production Plant shall equal Duke’s gross plant balance as recorded in FERC Balance Sheet Account No. 101, FERC Electric Plant Account Nos. 310-347 and Balance Sheet Account Nos. 102 and 106 tentatively classified to FERC Electric Plant Account Nos. 310-347, plus an adjustment to add Contra AFUDC related to production plant construction work in progress in included in rate base.

Production Plant Materials and Supplies shall equal Duke’s balance as assigned to production as recorded in FERC Account No. 154.

Revenue Tax Rate shall equal 1.0 minus the applicable revenue or gross receipts tax rate(s) to which Duke is subject for the revenues or gross receipts that Duke receives under this Agreement

Tax Deduction for Manufacturing Activities shall equal Duke’s annual amount of tax deduction under Section 102 of the American Jobs Creation Act of 2004.

Total Plant in Service shall equal Duke’s total gross plant balance as recorded in FERC Balance Sheet Account No. 101, Electric Plant Account Nos. 301-399, and amounts in FERC Balance Sheet Account Nos. 102 and 106, plus an adjustment to add Contra AFUDC related to construction work in progress included in rate base.

Unamortized Loss on Reacquired Debt shall equal Duke’s expenses as recorded in FERC Account No. 189.

Unamortized Gain on Reacquired Debt shall equal Duke’s amounts included in FERC Account No. 257.

Variable Non-Fuel Production Operation and Maintenance Expense shall equal Duke’s expenses as recorded in FERC Account Nos. 510, 512, 513, 528, 530, 531, and 544.

II.	Demand Rate

The Demand Rate shall be the Production Capacity Revenue Requirement as determined in Part III below, divided by Duke’s Average Peak Hour Load, and further divided by the Revenue Tax Rate. The Monthly Demand Rate shall be equal to the Demand Rate divided by twelve (12).

III.	Production Capacity Revenue Requirement

The Production Capacity Revenue Requirement shall equal the sum of Duke’s (A) Return and Associated Income Taxes, (B) Production Depreciation Expense, (C) Decommissioning Expense, (D) Production Related General Taxes, (E) Fixed Production Operation and Maintenance Expense, (F) Purchased Power Capacity Expenses, (G) Production Related Administrative and General Expense, (H) Production Related Other Amortization Expense and (I) Capacity Credit for Revenue from Non-Associated Utility Sales.

A.	Return and Associated Income Taxes shall equal the product of the Production Investment Base and the Cost of Capital Rate.

Production Investment Base

The Production Investment Base shall equal the average of the beginning and end-of-year balances of (a) Production Plant, plus (b) Production Related General and Intangible Plant, plus (c) Production Plant Held for Future Use, less (d) Production Related Depreciation Reserve, less (e) Production Related Net Asset Retirement Costs, plus (f) Nuclear Fuel Inventory, plus (g) Fossil Fuel Inventory, less (h) Production Related Accumulated Deferred Income Taxes, plus (i) Production Related Loss on Reacquired Debt, (j) less Production Related Gain on Reacquired Debt, plus (k) FAS 106 and FAS 109 Regulatory Assets/Liabilities, plus (l) Other Regulatory Assets/Liabilities, plus (m) Production Prepayments, plus (n) Production Materials and Supplies, plus (o) Production Related Cash Working Capital.

(a)

Production Plant shall equal Production Plant as defined above.

(b)

Production Related General and Intangible Plant shall equal the sum of General Plant plus Intangible Plant multiplied by the Production Wages and Salaries Allocation Factor.

(c)

Production Plant Held for Future Use shall equal Plant Held for Future Use multiplied by the Production Plant Allocation Factor.

(d)

Production Related Depreciation Reserve shall equal Production Depreciation Reserve plus Production Related General and Intangible Plant Depreciation Reserve; where Production Related General and Intangible Plant Depreciation Reserve shall equal the sum of General Plant Depreciation Reserve plus Intangible Plant Amortization Reserve, multiplied by the Production Wages and Salaries Allocation Factor.

(e)

Production Related Net Asset Retirement Costs shall equal Duke’s asset retirement cost balance as recorded in FERC Account No. 101 for Production Plant less the associated accumulated depreciation balance as recorded in FERC Account No. 108.

(f)

Nuclear Fuel Inventory shall equal Duke’s balance of investment in nuclear fuel as recorded in FERC Account Nos. 120.1 – 120.6.

(g)

Fossil Fuel Inventory shall equal Duke’s balance of investment in fossil fuel as recorded in FERC Account No. 151.

(h)

Production Related Accumulated Deferred Income Taxes shall equal Total Accumulated Deferred Income Taxes multiplied by the Production Plant Allocation Factor.

(i)

Production Related Loss on Reacquired Debt shall equal Unamortized Loss on Reacquired Debt multiplied by the Production Plant Allocation Factor.

(j)

Production Related Gain on Reacquired Debt shall equal Unamortized Gain on Reacquired Debt multiplied by the Production Plant Allocation Factor.

(k)

FAS 106 and FAS 109 Regulatory Assets/Liabilities shall equal Duke’s balance of FAS 106 related costs as recorded in FERC Account Nos. 182.3 and 254 multiplied by the Production Wages and Salaries Allocation Factor, plus Duke’s balance of FAS 109 related costs as recorded in FERC Account Nos. 182.3 and 254 multiplied by the Production Plant Allocation Factor.

(l)

Other Regulatory Assets/Liabilities shall equal Duke’s balance of Other Regulatory Assets/Liabilities as appropriate; provided, that in order to include any amounts in this item, Duke shall make a filing with FERC under Section 205 of the Federal Power Act.

(m)

Production Prepayments shall equal Duke’s Prepayments in FERC Account 165 multiplied by the Production Wages and Salaries Allocation Factor.

(n)

Production Materials and Supplies shall equal Production Plant Materials and Supplies as defined above.

(o)

Production Related Cash Working Capital shall be a 12.5% allowance (45 days/360 days) of Fixed Production Operation and Maintenance Expense,

Variable Production Non-Fuel Operation and Maintenance Expenses and Production Related Administrative and General Expense.

Cost of Capital Rate

The Cost of Capital Rate will equal (a) Duke’s Weighted Cost of Capital, plus (b) Federal Income Tax plus (c) State Income Tax.

(a) The Weighted Cost of Capital shall be calculated based upon a proxy capital structure of 45% long term debt and 55% common equity and shall equal the sum of:

(i)

the long term debt component, which shall equal the product of 45% and Duke’s long term debt expenses recorded in FERC Account Nos. 427, 428, 428.1, 429, 429.1, and 430 divided by Duke’s long-term debt balance as recorded in FERC Account Nos. 221 through 227, and

(ii)

the return on equity component , which shall equal the product of 55% and Duke’s return on equity (ROE) of 11.0%.

(b)

Federal Income Tax shall equal

[A+(B+C+D)/E] x (FT) / (1-FT)

where FT is the Federal Income Tax Rate and A is the return on equity component, as determined in Sections III.A.2.(a)(ii) above, B is Production Related Amortization of Investment Tax Credits, , C is Duke’s annual amount of Tax Deduction for Manufacturing Activities, D is the Equity AFUDC component of Production Depreciation Expense as defined in Section III.B below, and E is Production Investment Base as Determined in III.A.1 above.

(c)

State Income Tax shall equal

[A+(B+C+ D)/E + Federal Income Tax]x(ST)/ (l -ST)

where ST is the State Income Tax Rate. A is the return on equity component determined in Sections lll.A.2.(a)(ii) above, B is the Amortization of Investment Tax Credits, C is Duke’s

annual amount of Tax Deduction for Manufacturing Activities, D is the equity AFUDC component of Production Depreciation Expense as defined in Section III.B. below, E is the Production Investment Base as determined in III.A.l above and Federal Income Tax is the rate determined in Section III.A.2.(b) above.

Production Depreciation Expense shall equal the sum of Depreciation Expense for Production Plant, plus an allocation of General and Intangible Plant Deprecation Expense calculated by multiplying the sum of General Plant Depreciation Expense and Intangible Plant Amortization Expense by the Production Wages and Salaries Allocation Factor, less Decommissioning Expense as defined in III.C. below.

Decommissioning Expense shall equal $48,304,000 per year.

Production Related General Taxes shall equal the sum of General Tax Expense less revenue related taxes and Payroll Taxes, multiplied by the Production Plant Allocation Factor, and Payroll Taxes multiplied by the Production Wages and Salaries Allocation Factor.

Fixed Production Operation and Maintenance Expense shall equal Duke’s expenses as recorded in FERC Account Nos. 500, 502, 505-507, 511, 514, 517, 519, 520, 523-525, 529, 532, 535-543, 545, 546, 548-554, 556, and 557.

Purchased Power Expenses shall equal Duke’s expenses for purchased power recorded in FERC Account No. 555 less purchased power fuel costs included in the Fuel Rate determined in Section IV below.

Production Related Administrative and General Expenses shall equal the sum of (1) Administrative and General Expense multiplied by the Production Wages and Salaries Allocation Factor, (2) Property Insurance multiplied by the Production Plant Allocation Factor, (3) Expenses included in FERC Account 928 related to FERC Assessments multiplied by the Production Plant Allocation Factor, and (4) any other Production related expenses or assessments in FERC Account Nos. 928 or 930.1.

Production Related Other Amortization Expense shall equal Duke’s amortization expense recorded in FERC Account Nos. 406 and 407 either directly assigned to production or allocated to production using the Production Plant Allocation Factor or the Production Wages and Salaries Allocation Factor.

Credit for Revenue from Non-Associated Utility Sales shall equal Duke’s revenues from inter-system sales from Duke’s Generation System recorded in FERC Account 447 to the extent such sales are not included in the determination of Duke’s Average Peak Hour Load, less fuel recovered from such sales as determined in the Fuel Rate below, multiplied by 2/3.

IV.

Fuel Rate

The Fuel Rate shall equal F/S, and further divided by the Revenue Tax Rate, where:

F is the expense of fossil and nuclear fuel and purchased economic power, as defined in 18 C.F.R. § 35.14(a)(2) (2005), for the calendar year period; provided that for purposes of this calculation described in 18 C.F.R. § 35.14(a)(2) (2005) the cost of fossil fuel shall include, in addition to those items set forth in 18 C.F.R. § 35.14(a)(6), expenses recorded in Account No. 509 for the calendar year period.

S is all kWh sold (compensated for losses to the point at which power is available for transmission ), excluding inter-system sales, for the calendar year period.

Variable O&M Rate

The Variable O&M rate shall equal Variable Non-Fuel Production Operation and Maintenance Expense divided by S as determined in Section IV above, and further divided by the Revenue Tax Rate.

Attachment 3-1

Example showing the calculation of the Excess Annual Capacity Charges in the

Duke-Blue Ridge Agreement, Duke-Piedmont Agreement

and Duke-Rutherford Agreement

The purpose of this attachment is to provide an example showing the calculation of the Excess Annual Capacity Charges provided in Section 3.5.2.3.5 of the above-identified agreements. Blue Ridge, Piedmont and Rutherford are referred to individually as BR, P and R, respectively, and collectively as the EMC Group.

Assumptions:

Hour of maximum integrated sixty minute Duke Schedule 1 Demands during July and August 2007: 4:00-5:00 pm, July 14, 2007.


	BR (kW)	P (kW)	R (kW)
EMC Coincident Peak Demand (7-14-07 4-5 pm)	225,000	150,000	425,000
EMC Base Obligation (7-14-07 4-5pm)	125,000	175,000	300,000

EMC Group Coincident Peak Demand (7-14-07, 4-5 pm): 800,000 kW

EMC Group Base Obligation (7-14-07, 4-5 pm): 600,000 kW

Annual Capacity Quantity = 148,000 kW

Step 1

Calculate EMC Group Excess Annual Capacity Quantity per Section 3.5.2.3.5.


EMC Group Coincident Peak Demand (7-14-07 4-5 pm)		800,000 kW
minus EMC Group Base Obligation (7-14-07 4-5 pm)		- 600,000 kW
minus Annual Capacity Quantity		- 148,000 kW
EMC Group Excess Annual Capacity Quantity		52,000 kW

Step 2

Calculate EMC Excess Annual Capacity Quantity per Section 3.5.2.3.5.1


	A EMC Coincident Peak Demand (7-14-07 4-5pm) (kW)	B minus EMC Base Obligation (7-14-07 4-5 pm) (kW)	C minus EMC Annual Capacity Quantity (kW)	D EMC Excess Annual Capacity Quantity ¹ (kW)
BR	225,000	125,000	42,000	58,000
P	150,000	175,000	23,000	0
R	425,000	300,000	83,000	42,000

¹	Cannot be less than zero.

Step 3

Calculate EMC Group Combined Excess Annual Capacity Quantity per Section 3.5.2.3.5.2.


BR Excess Annual Capacity Quantity		58,000 kW
P Excess Annual Capacity Quantity		0 kW
R Excess Annual Capacity Quantity		42,000 kW

EMC Group Combined Excess Annual Capacity Quantity		100,000 kW

Step 4

Calculate Excess Annual Amount per Section 3.5.2.3.5.


	A EMC Excess Annual Capacity Quantity (kW)	B EMC Group Combined Excess Annual Capacity Quantity (kW)	C EMC Group Excess Capacity Quantity (kW)	D EMC Excess Annual Amount *( ( A / B) C) (kW)**
BR	58,000	100,000	52,000	30,160
P	0	100,000	52,000	0
R	42,000	100,000	52,000	21,840

Step 5

Calculate Excess Annual Capacity Charge per Section 3.5.2.3.5.


	A EMC Excess Annual Amount (kW)	B Annual Capacity Price ($/kW-year)	C Excess Annual Capacity Charge
BR	30,160	45.60	$	1,375,296
P	0	45.60	$	0
R	21,840	45.60	$	995,904

Attachment 4-1

Piedmont

EMC’s Base Obligation (MW) (as defined in Section 4.2.2)

Fixed Forward Resource (MW) (as defined in Section 5.1.1)


	Weekday
Hour	1	2	3	4	5	6	7	8	9	10	11	12	13	14	15	16	17	18	19	20	21	22	23	24
Sep-06	39	37	37	37	37	39	44	43	41	41	41	42	43	44	45	46	48	50	51	51	52	50	46	41
Oct-06	30	29	28	28	30	37	48	46	39	36	34	33	32	32	33	34	37	43	48	52	51	48	41	35
Nov-06	40	39	40	41	42	48	55	52	48	44	41	39	37	37	36	37	40	48	52	52	52	50	46	42
Dec-06	45	44	44	45	48	55	66	65	59	54	49	46	43	41	40	41	47	59	66	66	66	63	58	51
Jan-07	54	55	57	60	62	73	84	78	74	73	66	60	55	52	51	52	58	69	78	78	78	76	73	68
Feb-07	41	41	42	44	46	55	69	67	58	55	53	51	48	48	49	54	63	74	78	80	80	73	65	56
Mar-07	33	32	32	33	36	44	55	51	44	39	37	34	33	32	30	31	34	39	47	52	51	48	42	37
Apr-07	30	29	29	30	31	37	44	41	37	34	32	31	30	30	29	29	31	34	36	39	41	41	37	32
May-07	30	29	29	28	29	33	39	39	35	34	33	33	33	33	33	34	36	39	40	40	42	43	39	34
Jun-07	41	39	39	39	39	40	43	44	42	43	44	45	46	46	47	48	49	51	53	52	51	52	48	45
Jul-07	51	47	44	42	41	42	45	46	47	52	58	63	67	67	69	73	74	80	83	81	78	74	66	58
Aug-07	51	47	44	43	42	44	48	48	46	48	53	60	66	68	69	73	74	77	84	79	76	74	66	60
Sep-07	37	35	34	34	34	37	41	40	38	38	38	39	40	41	42	43	45	46	47	48	48	46	43	39
Oct-07	28	27	26	27	28	34	45	43	36	33	32	30	30	30	30	32	34	40	45	48	48	44	39	33
Nov-07	37	37	37	37	39	44	51	48	44	41	38	37	35	34	33	34	37	44	48	49	48	46	43	39
Dec-07	42	41	41	42	44	51	62	60	55	50	46	43	40	38	37	38	44	55	61	62	61	59	54	48
Jan-08	55	57	59	61	65	74	87	81	76	74	67	62	58	54	53	54	60	71	80	81	80	79	75	70
Feb-08	43	43	44	45	48	57	72	69	60	56	54	53	51	49	51	55	66	76	80	81	83	75	67	59
Mar-08	34	33	34	34	37	45	57	53	45	40	37	36	34	32	32	32	35	41	48	53	53	50	44	38
Apr-08	31	30	30	31	32	37	45	43	38	35	33	32	31	30	30	30	32	34	37	39	43	42	38	34
May-08	32	30	30	30	30	34	41	40	36	35	34	34	34	34	34	35	37	39	41	41	44	44	40	35
Jun-08	43	41	40	40	40	41	44	45	44	44	45	46	47	48	48	50	51	53	54	54	53	53	50	46
Jul-08	53	48	46	44	43	44	46	47	48	54	60	66	69	69	72	75	76	83	86	83	81	77	68	59
Aug-08	52	48	46	44	44	46	50	50	48	49	55	62	68	70	73	75	77	80	87	81	79	76	68	61
Sep-08	38	36	35	35	35	37	42	41	39	39	39	40	41	42	44	44	46	48	48	49	50	48	44	40
Oct-08	30	27	27	27	29	36	46	44	37	34	32	32	31	31	32	32	36	41	46	50	49	46	40	34
Nov-08	39	38	38	39	41	46	53	50	46	42	39	37	36	35	34	35	39	46	50	51	50	48	44	40
Dec-08	44	42	43	44	46	53	64	62	56	52	47	44	41	39	38	39	45	57	63	64	63	61	55	49

Note: Hour 1 refers to 12:00 a.m. - 12:59:59 a.m. Eastern Time, Hour 2 refers to 1:00 a.m. - 1:59:59 a.m. Eastern Time, etc.

Attachment 4-1 to Duke-Piedmont Agreement

Piedmont

EMC’s Base Obligation (MW) (as defined in Section 4.2.2)

Fixed Forward Resource (MW) (as defined in Section 5.1.1)


	Weekday
Hour	1	2	3	4	5	6	7	8	9	10	11	12	13	14	15	16	17	18	19	20	21	22	23	24
Jan-09	58	59	60	63	67	77	90	83	80	76	69	65	59	55	55	55	62	73	83	83	83	81	77	73
Feb-09	44	44	45	46	49	59	74	71	62	59	56	55	52	51	53	58	67	79	83	84	86	78	69	60
Mar-09	35	34	34	36	38	46	59	55	46	41	39	37	35	34	32	33	37	42	50	55	55	51	45	39
Apr-09	32	31	31	32	33	39	47	44	39	37	34	33	32	32	31	31	33	36	39	41	44	44	39	34
May-09	32	31	30	30	31	35	42	41	37	36	36	35	36	36	36	37	39	41	42	43	45	46	41	36
Jun-09	44	42	41	41	41	43	46	46	45	46	46	48	49	49	50	51	53	55	56	55	55	55	52	48
Jul-09	54	50	47	45	44	45	48	48	50	55	62	67	72	72	74	77	80	86	88	87	83	80	71	61
Aug-09	54	50	48	46	45	47	51	52	50	51	57	64	70	73	74	78	80	82	90	84	81	79	71	63
Sep-09	39	37	37	36	37	39	44	43	40	40	41	41	43	44	45	46	48	49	51	51	51	49	46	41
Oct-09	30	29	28	28	30	37	48	46	39	35	34	32	32	32	32	34	37	42	48	52	51	48	41	35
Nov-09	39	39	39	40	41	47	54	52	47	44	41	39	37	36	35	37	40	47	51	52	51	50	46	41
Dec-09	45	44	44	45	48	55	66	65	59	53	49	46	43	41	39	41	46	59	66	66	66	62	58	51
Jan-10	59	60	62	66	69	80	93	87	81	80	72	66	61	58	56	58	63	76	86	86	86	83	80	75
Feb-10	46	46	46	48	51	60	76	73	64	60	58	56	53	53	54	59	69	81	86	87	88	80	71	62
Mar-10	37	36	36	37	39	48	60	56	48	43	40	38	36	34	34	34	37	44	52	57	56	53	47	40
Apr-10	33	32	32	32	34	40	48	46	41	37	35	34	33	32	32	32	34	37	39	42	46	45	41	36
May-10	34	32	32	31	32	37	44	43	39	37	37	37	37	37	37	37	39	42	44	44	46	47	43	37
Jun-10	46	44	43	42	42	44	47	48	46	47	48	49	51	51	52	53	54	56	58	58	57	57	53	49
Jul-10	56	51	48	46	46	46	49	51	51	58	63	69	74	74	76	80	82	88	91	89	86	82	73	63
Aug-10	55	52	49	47	46	48	53	53	51	53	59	66	73	75	76	80	82	85	93	87	84	81	73	66
Sep-10	40	39	38	37	37	40	45	44	41	41	42	43	44	45	46	47	49	51	52	53	53	51	47	43
Oct-10	31	30	29	29	31	38	49	47	39	37	34	33	33	33	33	34	38	44	49	53	53	49	43	36
Nov-10	41	40	41	41	43	48	56	53	48	45	42	40	39	37	37	37	41	49	53	54	53	51	47	43
Dec-10	46	45	46	46	49	57	68	67	60	55	51	47	44	41	41	42	48	60	67	68	67	65	59	52

Attachment 4-1 to Duke-Piedmont Agreement

Piedmont

EMC’s Base Obligation (MW) (as defined in Section 4.2.2)

Fixed Forward Resource (MW) (as defined in Section 5.1.1)


	Weekend
Hour	1	2	3	4	5	6	7	8	9	10	11	12	13	14	15	16	17	18	19	20	21	22	23	24
Sep-06	40	38	37	37	37	37	37	39	42	44	44	46	47	48	49	50	51	51	51	51	51	49	45	42
Oct-06	30	27	26	25	26	27	30	34	40	43	43	42	43	43	42	43	44	45	47	49	48	44	39	34
Nov-06	35	34	34	34	34	35	37	41	45	46	44	42	41	39	38	38	40	45	48	48	46	44	41	38
Dec-06	49	48	47	48	49	51	55	62	69	67	63	58	55	51	49	49	54	64	68	68	67	66	61	55
Jan-07	73	73	73	74	75	77	80	83	88	87	81	73	67	62	59	56	60	69	74	73	72	68	62	57
Feb-07	48	48	49	51	54	58	61	68	73	69	60	53	45	41	38	36	39	44	55	60	60	59	53	48
Mar-07	32	30	30	30	32	34	37	43	48	48	46	43	41	39	37	36	37	39	45	50	49	46	42	37
Apr-07	30	28	26	27	27	29	31	34	37	39	38	37	36	35	34	34	34	35	36	37	39	39	35	32
May-07	31	30	29	29	30	30	32	34	38	39	39	39	39	39	39	39	39	40	41	41	42	43	39	36
Jun-07	42	40	39	39	38	39	39	41	44	46	47	48	49	49	50	51	51	51	51	51	50	50	48	44
Jul-07	46	42	39	38	37	37	37	41	48	55	60	64	69	73	74	76	78	79	77	75	73	73	66	57
Aug-07	59	54	54	50	48	48	47	50	58	66	71	76	81	84	86	87	88	88	87	84	83	80	73	66
Sep-07	37	36	34	34	34	34	35	37	39	41	41	43	44	45	46	46	47	48	47	47	48	46	42	39
Oct-07	28	25	24	24	24	25	27	32	37	40	40	39	39	40	39	40	41	42	44	46	44	41	36	31
Nov-07	32	32	31	31	32	33	35	39	42	43	41	39	38	37	35	36	37	42	44	44	43	41	39	36
Dec-07	46	44	44	44	46	48	51	58	64	62	59	54	51	48	46	46	51	60	63	63	62	60	57	51
Jan-08	74	75	76	76	78	80	82	87	91	89	83	76	69	65	60	59	62	71	76	74	74	70	65	59
Feb-08	50	49	51	53	55	59	63	70	75	71	62	54	47	42	39	37	39	45	57	62	62	60	55	49
Mar-08	33	32	31	32	32	35	38	44	49	50	47	44	42	40	38	37	39	41	46	51	51	48	44	39
Apr-08	30	29	27	28	29	30	32	34	39	39	39	38	37	36	35	35	35	37	37	39	41	40	37	32
May-08	32	31	30	30	30	31	33	36	39	41	41	40	40	40	40	40	41	41	42	42	44	44	41	37
Jun-08	44	41	41	40	39	39	40	42	45	48	48	50	51	51	52	52	53	53	53	52	51	52	49	46
Jul-08	48	44	41	39	38	38	39	42	49	56	62	66	71	75	76	79	80	81	80	77	76	74	67	59
Aug-08	60	56	55	52	50	49	48	51	59	67	74	79	83	87	88	90	90	90	90	87	87	83	75	67
Sep-08	38	37	36	35	35	35	37	38	41	42	43	44	45	46	47	48	48	49	48	49	49	47	44	41
Oct-08	29	26	25	25	25	26	28	32	39	41	41	41	41	41	41	41	42	44	45	48	46	43	37	32
Nov-08	34	32	32	32	33	34	37	40	44	44	43	41	39	38	37	37	39	44	46	46	44	43	40	37
Dec-08	48	46	46	46	47	49	53	59	66	65	61	55	53	49	47	48	52	62	66	66	65	62	59	53

Attachment 4-1 to Duke-Piedmont Agreement

Piedmont

EMC’s Base Obligation (MW) (as defined in Section 4.2.2)

Fixed Forward Resource (MW) (as defined in Section 5.1.1)


	Weekend
Hour	1	2	3	4	5	6	7	8	9	10	11	12	13	14	15	16	17	18	19	20	21	22	23	24
Jan-09	77	77	78	80	81	83	85	89	94	92	87	78	72	67	62	60	64	74	80	76	76	73	67	61
Feb-09	52	51	53	55	58	61	66	73	78	73	64	56	48	44	40	39	41	46	59	64	65	62	56	51
Mar-09	34	32	32	32	34	36	39	46	51	51	48	46	44	41	39	39	39	42	48	53	53	49	44	39
Apr-09	31	30	27	29	30	31	33	36	39	41	41	39	39	37	37	36	37	37	39	39	42	41	37	33
May-09	33	32	31	31	31	32	34	37	40	42	42	41	41	41	41	41	42	43	44	43	45	46	42	38
Jun-09	45	43	41	41	41	41	41	44	46	49	51	51	52	53	53	54	55	55	55	54	53	53	51	47
Jul-09	49	45	42	40	39	39	40	43	51	59	63	68	73	78	80	81	83	83	83	80	78	76	69	61
Aug-09	62	58	58	53	51	51	50	53	61	69	76	81	87	90	91	93	94	94	93	90	89	86	78	69
Sep-09	39	38	37	37	37	37	37	39	42	44	44	46	47	48	48	50	51	51	51	51	51	48	45	42
Oct-09	30	27	26	25	25	27	30	34	40	43	43	42	42	42	42	43	44	45	46	49	48	44	39	33
Nov-09	34	34	33	33	34	35	37	41	45	46	44	42	40	39	38	38	40	45	48	47	46	44	41	38
Dec-09	49	47	47	48	48	51	55	61	68	67	62	58	54	51	48	49	54	64	67	67	67	65	60	55
Jan-10	80	80	81	81	83	85	88	92	98	95	89	81	74	69	65	62	66	76	81	80	79	75	69	62
Feb-10	53	53	54	56	60	63	67	75	80	75	66	58	50	45	41	39	42	48	60	66	67	64	59	52
Mar-10	36	34	33	34	34	37	41	47	53	53	51	47	45	43	41	40	41	44	50	55	54	51	46	41
Apr-10	32	31	28	30	30	32	34	37	41	42	41	41	40	39	37	37	38	39	39	41	44	42	39	34
May-10	34	32	32	32	32	33	35	38	41	44	44	43	43	43	43	43	44	44	45	44	46	47	44	39
Jun-10	46	44	43	42	42	42	43	45	48	51	52	53	54	55	55	55	56	57	57	55	55	55	52	48
Jul-10	51	46	44	41	41	41	41	44	53	60	66	70	76	80	81	84	86	87	85	83	81	80	72	62
Aug-10	65	60	59	55	53	52	52	55	63	72	78	83	89	94	95	95	97	97	96	93	92	88	80	72
Sep-10	41	39	38	37	37	38	39	40	43	45	46	47	48	49	51	51	52	53	52	52	53	50	46	43
Oct-10	31	28	27	26	26	27	30	34	41	44	44	44	44	44	44	44	45	46	48	51	49	46	39	34
Nov-10	36	34	34	34	35	37	39	42	46	47	46	44	41	40	39	39	41	46	49	48	47	46	42	39
Dec-10	51	48	48	49	51	53	57	63	70	69	65	60	55	53	50	51	55	66	69	69	69	67	62	57

Attachment 4-1 to Duke-Piedmont Agreement

Attachment 4-2

Calculation of Reduction to EMC’s Base Obligation and EMC Group’s Base Obligation During Light Load Periods

I. Definitions

1. The “Carolina Power & Light Service Obligation Resources” or “SORs” means those generation and purchased capacity resources provided to NCEMC by CP&L and used by NCEMC to serve NCEMC load pursuant to the Power Supply Agreement.

2. The “Power Supply Agreement” means the Power Supply Agreement Dated November 2, 1998 Between North Carolina Electric Membership Corporation and Carolina Power & Light Company, d/b/a Progress Energy Carolinas, Inc., as amended, filed at FERC in Docket No. ER05-722-000 on June 30, 2005.

3. The “1996 SO” means the Service Obligation assumed by NCEMC on January 1, 1996 in the amount of 204.3 MW including losses.

4. “SOR A” means the 225 MW of electric capacity and energy that CP&L provides to NCEMC pursuant through December 31, 2015 pursuant to Section 2.1(a)(1) of the Power Supply Agreement.

5. “SOR E” means the 225 MW of electric capacity and energy that CP&L provides to NCEMC pursuant through December 31, 2013 pursuant to Section 2.1(a)(4) of the Power Supply Agreement.

6. “NCEMC Catawba Resource Entitlement” or “CRE” means NCEMC’s 623.5 MW ownership interest in the Catawba Nuclear Station.

7. “NCEMC’s CP&L Native Load” or “NCNL” means the electric capacity and energy demands (kW) imposed on NCEMC by its member cooperatives in CP&L’s existing Control Areas, and which are served by CP&L under the Power Supply Agreement (excluding the 1996 SO).

8. “NCEMC’s Duke Native Load” or “NDNL” means the electric capacity and energy demands (kW) imposed on NCEMC by its member cooperatives in Duke’s Control Area.

II. Calculation of Reduction in EMC’s Base Obligation and EMC Group’s Base Obligation During Light Load Periods (through December 31, 2008)

EMC’s Base Obligation and EMC Group’s Base Obligation during an Hour shall be subject to reduction during the period commencing on the Commencement Date and continuing through December 31, 2008 in accordance with the following:

A. NCEMC’s contractual right to SO 1996, SOR A and SOR E (654.3 MW rounded to 655 MW) is subject to reduction based on a comparison between 655 MW and NCEMC’s CP&L Native Load (NCNL).

B. In the event that NCEMC’s CP&L Native Load during the Hour is less than 655 MW, EMC’s Base Obligation and EMC Group’s Base Obligation for the Hour shall be reduced as follows:

C. If 655 MW minus NCNL is equal to or less than 225 MW, the reduction in EMC’s Base Obligation shall be equal to the amount set forth in Equation 1 below:

Equation 1: ( ( 655 MW - NCNL ) / 225 ) * 5

D. If 655 MW minus NCNL is greater than 225 MW, the reduction in EMC’s Base Obligation shall be equal to 5 MW plus the amount set forth in Equation 2 below:

Equation 2: ( ( 430 MW - NCNL ) / 225 ) * 5

E. If 655 MW minus NCNL is equal to or less than 225 MW, the reduction in EMC Group’s Base Obligation shall be equal to the amount set forth in Equation 3 below:

Equation 3: ( ( 655 MW - NCNL ) / 225 ) * 33

F. If 655 MW minus NCNL is greater than 225 MW, the reduction in EMC Group’s Base Obligation shall be equal to 33 MW plus the amount set forth in Equation 4 below:

Equation 4: ( ( 430 MW - NCNL ) / 225 ) * 33

G. Example: If NCNL is equal to 565 MW during an Hour, the reduction in EMC’s Base Obligation for the Hour shall be equal to ( ( 655 MW – 565 MW ) / 225 ) * 5 or 2 MW, and the reduction in EMC Group’s Base Obligation for the Hour shall be equal to ( (655 MW - 565 MW) / 225 ) * 33, or 13.2 MW.

III. Calculation of Reduction in EMC’s Base Obligation and EMC Group’s Base Obligation During Light Load Periods (January 1, 2009 through December 31, 2010)

EMC’s Base Obligation and EMC Group’s Base Obligation during an Hour shall be subject to reduction during the period commencing on January 1, 2009 and continuing through December 31, 2010 in accordance with the following:

A. NCEMC’s contractual right to SO 1996 and SOR A (429.3 MW rounded to 430 MW) is subject to reduction based on a comparison between 430 MW and NCEMC’s CP&L Native Load (NCNL).

B. In the event that NCEMC’s CP&L Native Load during the Hour is less than 430 MW, EMC’s Base Obligation for the Hour shall be reduced as follows:

Equation 5: ( (430 MW - NCNL ) / 225 ) * 5

C. In the event that NCEMC’s CP&L Native Load during the Hour is less than 430 MW, EMC Group’s Base Obligation for the Hour shall be reduced as follows:

Equation 6: ( ( 430 MW - NCNL ) / 225 ) * 33

D. Example: If NCNL is equal to 340 MW during an Hour, the reduction in EMC’s Base Obligation for the Hour shall be equal to ( ( 430 MW – 340 MW ) / 225 ) * 5 MW, or 2 MW, and the reduction in EMC Group’s Base Obligation for the Hour shall be equal to ( ( 430 MW – 340 MW ) / 225 ) * 33, or 13.2 MW.

IV. Calculation of Reduction in EMC’s Base Obligation and EMC Group’s Base Obligation During Light Load Periods for the Catawba Resource Entitlement

In addition to the reductions to EMC’s Base Obligation and EMC Group’s Base Obligation set forth under Sections II and III above, EMC’s Base Obligation and EMC Group’s Base Obligation shall be subject to reduction as set forth in this Section IV.

A. In the event that NCEMC’s Duke Native Load during an Hour is less than 623.5 MW and a nuclear unit at Catawba Nuclear Station or McGuire Nuclear Station is off-line or derated during the Hour, EMC’s Base Obligation for the Hour shall be reduced as follows:

Equation 7: (1 - ( NDNL / 623.5 MW) ) * 16 MW

B. In the event that NCEMC’s Duke Native Load during an Hour is less than 623.5 MW and a nuclear unit at Catawba Nuclear Station or McGuire Nuclear Station is off-line or derated during the Hour, EMC Group’s Base Obligation for the Hour shall be reduced as follows:

Equation 8: (1 - ( NDNL / 623.5 MW ) ) * 95 MW

C. Example: If NDNL is equal to 561.15 MW during an Hour, and a nuclear unit at Catawba Nuclear Station or McGuire Nuclear Station is off-line or derated during the Hour, the reduction in EMC’s Base Obligation for the Hour shall be equal to ( 1 -(561.15 MW / 623.5 MW) ) * 16 MW, which equals ( .1 ) * ( 16 MW ), or 1.6 MW, and the reduction in EMC Group’s Base Obligation for the Hour shall be equal to ( 1 - (561.15 MW / 623.5 MW ) ) * 95 MW, which equals ( .1 ) * ( 95 MW ), or 9.5 MW.

Attachment 4-3

Partial Requirements Resources

(Page 1 of 6)

Resource Name : AEP Baseload

Type of Resource : Baseload Resource

Delivery period : January 1, 2011 through December 31, 2012

Resource Capacity MW : 4

Must take resource : Yes, in the amount of MWs that NCEMC indicates is available in each hour.

Scheduling : A schedule must be submitted for each hour by Duke in the amount of MWs that NCEMC indicates is available.

Energy Pricing: NA

Force Majeure : “Force Majeure” means an event or circumstance which prevents one Party from performing its obligations under one or more Transactions, which event or circumstance was not anticipated as of the date the Transaction was agreed to, which is not within the reasonable control of, or the result of the negligence of, the Claiming Party, and which, by the exercise of due diligence, the Claiming Party is unable to overcome or avoid or cause to be avoided. Force Majeure shall not be based on (i) the loss of Buyer’s markets; (ii) Buyer’s inability economically to use or resell the Product purchased hereunder; (iii) the loss of failure of Seller’s supply; or (iv) Seller’s ability to sell the Product at a price greater than the Contract Price. Neither Party may raise a claim of Force Majeure based in whole or in part on curtailment by a Transmission Provider unless (i) such Party has contracted for firm transmission with a Transmission Provider for the Product to be delivered to or received at the Delivery Point and (ii) such curtailment is due to “force majeure” or “uncontrollable force” or a similar term as defined under the Transmission Provider’s tariff, provided however, that existence of a Force Majeure absent a showing of other facts and circumstances which in the aggregate with such factors establish that a Force Majeure as defined in the first sentence hereof has occurred.

Attachment 4-3 to Duke-Piedmont Agreement

Attachment 4-3

Partial Requirements Resources

(Page 2 of 6)

Resource Name : Catawba

Type of Resource : Baseload Resource

Delivery period : January 1, 2011 through December 31, 2021

Resource Capacity MW : 16

Must take resource : Yes, in the amount of MWs that NCEMC indicates is available in each hour.

Scheduling : A schedule must be submitted for each hour by Duke in the amount of MWs that NCEMC indicates is available.

Energy Pricing: NA

Force Majeure : The term “Force Majeure” as used herein shall mean any cause beyond the control of the party affected and which by reasonable efforts the party affected is unable to overcome, including without limitation the following: Acts of God: fire, flood, landslide, lightning, earthquake, hurricane, tornado, storm, freeze, or drought; blight, famine, epidemic, or quarantine; strike, lockout or other labor difficulty; act or failure to act of any party (and such party so acting or failing to act shall not used such act or failure to act to excuse any other obligation which it has under this Agreement); act or failure to act of any regulatory agency or other governmental authority; changes in the work or delays caused by public bidding requirements; theft; casualty; accident; equipment breakdown, failure or shortage of, or inability to obtain from usual sources, goods, labor, equipment, information or drawings, machinery, supplies, energy, fuel or materials; embargo; injunction; litigation or arbitration with suppliers or vendors; shortage of rolling stock; arrest; war; civil disturbance; explosion; acts of public enemies; sabotage; or breach of contract by any supplier, contractor, sub-contractor, laborer or materialman. Any party rendered unable to fulfill any obligation under this Agreement by reason of Force Majeure shall make reasonable efforts to remove such inability within a reasonable time.

Attachment 4-3 to Duke-Piedmont Agreement

Attachment 4-3

Partial Requirements Resources

(Page 3 of 6)

Resource Name : Dominion PPA

Type of Resource : Combined Cycle Resource

Delivery period : January 1, 2011 through December 31, 2014

Resource Capacity MW : 5

Must take resource : No

Resource Availability : Duke has the right but not the obligation to schedule the amount of MWs that NCEMC has indicated is available from this resource.

Min run time (Hours): 8

Scheduling :

•

Day ahead schedule to be submitted, with intraday changes allowed

•

Nominations must be made in whole MWs

•

Day ahead Schedules are those submitted before 8:00 a.m. EPT the day prior to flow. Intraday Schedules are those that are requested after the 8:00 a.m. EPT deadline above. All Schedule changes must occur at the top of the hour. Intraday Schedule changes require 2 hours advance notice.

•

Day ahead scheduling: Unlimited changes up to the allocation MWs

•

Intraday scheduling: Limit of two changes to the hourly Schedule for the remainder of the day. Each change to the hourly Schedule shall be no greater than 5%, for a cumulative maximum of 10% each hour. Additional changes will be accommodated on a best efforts basis.

Energy Pricing: For each month of the Delivery Period, the price for energy will equal the sum of Day-Ahead Energy Charge, the Intra-day Energy Charge, the Incremental Variable Charge and the Variable O&M Charge:

•

Day-ahead Energy Charge = the sum of each day in the month’s Day-Ahead Energy Price x energy scheduled Day-Ahead

•

Day-Ahead Energy Price = (Day-Ahead Fuel Index + Fuel Adder) x Heat Rate

•

Day-Ahead Fuel Index: Gas Daily : Daily Price Survey, Midpoint of the Daily Ranges, Appalachia, Dominion South Point. Gas Index for each Sat. and Sun. shall be the price specified for the Mon. immediately following such Sat. and Sun. In the event that Gas Daily no longer publishes this index, NCEMC and Dominion will agree upon a replacement index which will be passed through to the IM.

•

Intra-Day Energy Charge = the sum of each day in the month’s Intra-Day Energy Price x energy scheduled Intra-Day

•

Intra-Day Energy Price = (Intra-Day Fuel Index + Fuel Adder) x Heat Rate

Attachment 4-3 to Duke-Piedmont Agreement

Attachment 4-3

Partial Requirements Resources

(Page 4 of 6)

•

Intra-Day Fuel Index: The higher of the price in $/MMBtu for such calendar day or the next calendar day of Gas Daily : Daily Price Survey, Absolute of the Daily Ranges, Appalachia, Dominion South Point. Gas Index for each Sat and Sun shall be the price specified for the higher of the Monday or Tuesday immediately following such Saturday and Sunday.

•

Fuel Adder: $0.25/MMBtu

•

Heat Rate:

•

2006 heat rate: 7.730 MMBtu/MWh

•

Heat Rate Adjustment: The heat rate will be recalculated annually to reflect the actual energy costs from the previous year. The new heat rate will go into effect on February 1 of each year.

•

Incremental Variable Charge: There may be additional charges due to making Intra-day schedule changes.

•

Variable O&M Charge:

2011 = $3.81/MWh

2012 = $3.91/MWh

2013 = $4.01/MWh

2014 = $4.11/MWh

Force Majeure : “Force Majeure” means an event or circumstance which prevents one Party from performing its obligations under one or more Transactions, which event or circumstance was not anticipated as of the date the Transaction was agreed to, which is not within the reasonable control of, or the result of the negligence of, the Claiming Party, and which, by the exercise of due diligence, the Claiming Party is unable to overcome or avoid or cause to be avoided. Force Majeure shall not be based on (i) the loss of Buyer’s markets; (ii) Buyer’s inability economically to use or resell the Product purchased hereunder; (iii) the loss or failure of Seller’s supply; or (iv) Seller’s ability to sell the Product at a price greater than the Contract Price. Neither Party may raise a claim of Force Majeure based in whole or in part on curtailment by a Transmission Provider unless (i) such Party has contracted for firm transmission with a Transmission Provider for the Product to be delivered to or received at the Delivery Point and (ii) such curtailment is due to “force majeure” or “uncontrollable force” or a similar term as defined under the Transmission Provider’s tariff; provided, however, that existence of a Force Majeure absent a showing of other facts and circumstances which in the aggregate with such factors establish that a Force Majeure as defined in the first sentence hereof has occurred.

Attachment 4-3 to Duke-Piedmont Agreement

Attachment 4-3

Partial Requirements Resources

(Page 5 of 6)

Resource Name : SCEG

Type of Resource : Combined Cycle Resource

Delivery period : January 1, 2011 through December 31, 2012

Resource Capacity MW : 7

Must take resource : No

Resource Availability : Duke has the right but not the obligation to schedule the amount of MWs that NCEMC has indicated is available from this resource.

Min run time (Hours): 4

Firm Gas Transportation: Firm gas transportation has been procured for up to 16 hours a day. Therefore, operation of this resource is limited to no more than 16 hours a day.

Scheduling :

•

Day ahead schedule to be submitted, with intraday changes allowed

•

Nominations must be made in whole MWs

•

Day ahead scheduling: Unlimited changes up to the allocation MWs

•

Energy Pricing: For each month of the Delivery Period, the price for energy will equal the sum of Day-Ahead Energy Charge, the Intra-day Energy Charge and the Variable O&M Charge:

•

Day-ahead Energy Charge = the sum of each day in the month’s Day-Ahead Energy Price x energy scheduled Day-Ahead:

•

Day-Ahead Energy Price = (Day-Ahead Fuel Index + Fuel Adder) x Heat Rate

•

Day-Ahead Fuel Index: 102.6% of SONAT Mid-Point price as published in Gas Daily for Louisiana-OnShore South for gas to flow on such day

•

Intra-Day Energy Charge = the sum of each day in the month’s Intra-Day Energy Price x energy scheduled Intra-Day

•

Intra-Day Energy Price = (Intra-Day Fuel Index + Fuel Adder) x Heat Rate

Attachment 4-3 to Duke-Piedmont Agreement

Attachment 4-3

Partial Requirements Resources

(Page 6 of 6)

•

Intra-Day Fuel Index: 102.6% of the higher of the Gas Daily daily Mid-Point price for SONAT under the table for Louisiana-OnShore South for gas to flow such day or the Gas Daily daily Mid-Point price for SONAT under the table for Louisiana-OnShore South for gas to flow on the next trading day

•

Fuel Adder: $0.1/MMBtu

•

Heat Rate: 7.350 MMBtu/MWh

•

Variable O&M Charge:

2011 = $2.70/MWh

2012 = $2.76/MWh

Force Majeure : “Force Majeure” means an event or circumstance which prevents one Party from performing its obligations under one or more Transactions, which event or circumstance was not anticipated as of the date the Transaction was agreed to, which is not within the reasonable control of, or the result of the negligence of, the Claiming Party, and which, by the exercise of due diligence, the Claiming Party is unable to overcome or avoid or cause to be avoided. Force Majeure shall not be based on (i) the loss of Buyer’s markets; (ii) Buyer’s inability economically to use or resell the Product purchased hereunder; (iii) the loss of failure of Seller’s supply; or (iv) Seller’s ability to sell the Product at a price greater than the Contract Price. Neither Party may raise a claim of Force Majeure based in whole or in part on curtailment by a Transmission Provider unless (i) such Party has contracted for firm transmission with a Transmission Provider for the Product to be delivered to or received at the Delivery Point and (ii) such curtailment is due to “force majeure” or “uncontrollable force” or a similar term as defined under the Transmission Provider’s tariff; provided, however, that existence of a Force Majeure absent a showing of other facts and circumstances which in the aggregate with such factors establish that a Force Majeure as defined in the first sentence hereof has occurred.

Attachment 4-3 to Duke-Piedmont Agreement

Attachment 7-2

Example showing the calculation of the Monthly Demand Charges in the

Duke-Blue Ridge Agreement, Duke-Piedmont Agreement

and Duke-Rutherford Agreement

The purpose of this attachment is to provide an example showing the calculation of the Monthly Demand Charge provided in Section 7.1.4 of the above-identified agreements. Blue Ridge, Piedmont and Rutherford are referred to individually as BR, P and R, respectively, and collectively as the EMC Group.

Assumptions:

Hour in October in which the positive difference between the EMC Group Native Load and EMC Group’s Base Obligation is the greatest: 4:00-5:00 pm, October 14, 2006.


	BR (kW)	P (kW)	R (kW)
EMC Hourly Demand (10-14-06 4-5 pm)	75,000	275,000	375,000
EMC Base Obligation (10-14-06 4-5pm)	100,000	200,000	250,000

EMC Group Hourly Demand (10-14-06, 4-5 pm): 725,000 kW

EMC Group Base Obligation (10-14-06, 4-5 pm): 550,000 kW

Step 1

Calculate EMC Group Monthly Demand Quantity per Section 7.1.4.3.


EMC Group Hourly Demand		725,000kW
minus EMC Group Base Obligation		-550,000kW

EMC Group Monthly Demand Quantity		175,000kW

Step 2

Calculate EMC Monthly Demand Quantity per Section 7.1.4.1.


	A EMC Hourly Demand (10-14-06 4-5pm) (kW)	B minus EMC Base Obligation (10-14-06 4-5 pm) (kW)	C EMC Monthly Demand Quantity ² (kW)
BR	75,000	100,000	0
P	275,000	200,000	75,000
R	375,000	250,000	125,000

Step 3

Calculate EMC Group Combined Monthly Demand Quantity per Section 7.1.4.2.


BR Monthly Demand Quantity		0 kW
P Monthly Demand Quantity		75,000 kW
R Monthly Demand Quantity		125,000 kW

EMC Group Combined Monthly Demand Quantity		200,000 kW

Step 4

Calculate Monthly Demand Amount per Section 7.1.4.


	A EMC Monthly Demand Quantity (kW)	B EMC Group Combined Monthly Demand Quantity (kW)	C EMC Group Monthly Demand Quantity (kW)	D EMC Monthly Demand Amount *( ( A /B) C) (kW)**
BR	0	200,000	175,000	0
P	75,000	200,000	175,000	65,625
R	125,000	200,000	175,000	109,375

²	Cannot be less than zero.

Step 5

Calculate Monthly Demand Charge per Section 7.1.4.


	A EMC Monthly Demand Amount (kW)	B Monthly Demand Rate ($/kW-year)	C Monthly Demand Charge
BR	0	0.75	0
P	65,625	0.75	$49,218.75
R	109,375	0.75	$82,031.25

Attachment 7-3

Calculation of Piedmont Allocated Share of

Duke Total Hourly Energy Charge, EMC Group Total Hourly Energy Credit,

Inter-EMC Energy Charge and Inter-EMC Energy Credit

I. Definitions

1. The Inter-EMC Transfer Price for an Hour shall be equal to the simple average of the Duke Territorial Incremental Cost for the Hour and the Duke Territorial Decremental Cost for the Hour; provided, that for any Hour for which the EMC Group Energy Credit Amount is zero, the Inter-EMC Transfer Price for the Hour shall be equal to 101.5% of the Duke Territorial Incremental Cost for the Hour, and that for any Hour for which the EMC Group Energy Purchase Amount is zero, the EMC Transfer Price for the Hour shall be equal to 101.5% of the Duke Territorial Decremental Cost for the Hour.

2. All other capitalized terms shall have the meaning set forth in Section 1.1 of this Agreement.

II. Piedmont Allocated Share of the Duke Total Hourly Energy Charge

The Piedmont Allocated Share of the Duke Total Hourly Energy Charge for an Hour shall be equal to:

( C1 / A ) * D

Where:

A = EMC Group Combined Energy Purchase Amount

C1 = Piedmont Energy Purchase Amount

D = Duke Total Hourly Energy Charge

III. Piedmont Allocated Share of the Inter-EMC Energy Charge

The Piedmont Allocated Share of the Inter-EMC Energy Charge for an Hour shall be equal to:

( C1 / A ) * ( A—B ) * P

Where:

A = EMC Group Combined Energy Purchase Amount

B = EMC Group Energy Purchase Amount

C1 = Piedmont Energy Purchase Amount

P = Inter-EMC Transfer Price

IV. Piedmont Allocated Share of the EMC Group Total Hourly Energy Credit

The Piedmont Allocated Share of the EMC Group Total Hourly Energy Credit for an Hour shall be equal to:

( G1 / E ) * H

Where:

E = EMC Group Combined Energy Credit Amount

G1 = Piedmont Energy Credit Amount

H = EMC Group Total Hourly Energy Credit

V. Piedmont Allocated Share of the Inter-EMC Energy Credit

The Piedmont Allocated Share of the Inter-EMC Energy Credit for an Hour shall be equal to:

( G1 / E ) * ( E – F ) * P

Where:

E = EMC Group Combined Energy Credit Amount

F = EMC Group Energy Credit Amount

G1 = Piedmont Energy Credit Amount

P = Inter-EMC Transfer Price

- 2 -

Attachment 7-4

Example 1

Showing the Calculation of Blue Ridge, Piedmont and

Rutherford Allocated Shares of the Duke Total Hourly Energy Charge,

EMC Group Total Hourly Energy Credit, Inter-EMC Energy Charge and Inter-EMC Energy Credit

The purpose of this attachment is to provide an example showing the calculation of the charges and credits identified above for one Hour. For purposes of this example, Blue Ridge, Piedmont and Rutherford are referred to individually as BR, P and R, respectively, and collectively as the EMC Group.

I. ASSUMPTIONS:

A. Call and Put Signals during the Hour


	BR	P	R	EMC Group
Intervals 1-225 ¹ - Call Signal during each Interval (kW):	6,000	0	10,000	6,000
Intervals 1-225 - Put Signal during each Interval (kW)	0	10,000	0	0
Intervals 226-450 - Call Signal during each Interval (kW)	6,000	0	10,000	6,000
Intervals 226-450 - Put Signal during each Interval (kW)	0	10,000	0	0
Intervals 451-675 - Call Signal during each Interval (kW)	0	4,000	0	0
Intervals 451-675 - Put Signal during each Interval (kW)	9,000	0	9,000	14,000
Intervals 676-900 - Call Signal during each Interval (kW)	0	4,000	0	0
Intervals 676-900 - Put Signal during each Interval (kW)	9,000	0	9,000	14,000

Interval numbers refer to the Intervals during the Hour (e.g., Interval 1 is the first four seconds of the Hour, Interval 2 is the next four seconds, etc.). The Call and Put Signals are shown as the same in each of the first 225 Intervals of the Hour, and then again as the same in the next 225 Intervals and so on. This is a simplifying assumption, to make this example less cumbersome. In actual operation, the Parties anticipate that these positions would change frequently within the Hour.

B. Energy deliveries during the Hour ⁴


	BR	P	R	EMC Group
Hourly Energy Amount delivered from Duke - Intervals 1-225	1,500	0	2,500	1,500
Hourly Energy Amount delivered to Duke - Intervals 1-225	0	2,500	0	0
Hourly Energy Amount delivered from Duke - Intervals 226-450	1,500	0	2,500	1,500
Hourly Energy Amount delivered to Duke - Intervals 226-450	0	2,500	0	0
Hourly Energy Amount delivered from Duke - Intervals 451-675	0	1,000	0	0
Hourly Energy Amount delivered to Duke - Intervals 451-675	2,250	0	2,250	3,500
Hourly Energy Amount delivered from Duke - Intervals 676-900	0	1,000	0	0
Hourly Energy Amount delivered to Duke - Intervals 676-900	2,250	0	2,250	3,500

C. Incremental/Decremental Costs

Duke Territorial Incremental Cost: $0.10/kWh

Duke Territorial Decremental Cost: $0.10/kWh

⁴	These numbers sum the four-second Call and Put Signals from Part I.A. For example, 6,000 kW delivered by Duke in each of the 225 four-second Intervals (15 minutes) equal 1,500 kWh (6,000 KW * 225 Intervals / 900 Intervals / Hour = 1500 kWh).

- 2 -

II. CALCULATIONS

A. Calculation of Blue Ridge, Piedmont and Rutherford Allocated Shares of the Duke Total Hourly Energy Charge

Step 1

Sum the energy deliveries by Duke to BR for all Intervals over the entire Hour (column 1). Repeat calculation for P and R (columns 2-3). Sum columns 1-3 (column 4). Sum the energy deliveries by Duke to the EMC Group for all Intervals over the entire Hour (column 5).


Column number	1	2	3	4	5
	BR ⁵	P ⁶	R ⁷	Sum ⁸	Aggregate EMC Group ⁹
Energy delivered by Duke (kW)	3,000	2,000	5,000	10,000	3,000

Step 2

Calculate the percentage that each Customer contributed to the energy deliveries by Duke (Customer Buy / Sum of Customer Buys)

BR ¹⁰

P ¹¹

R ¹²

Sum

Energy delivered by Duke

30.00

20.00

50.00

100.00

⁵	Blue Ridge Energy Purchase Amount

⁶	Piedmont Energy Purchase Amount

⁷	Rutherford Energy Purchase Amount

⁸	EMC Group Combined Energy Purchase Amount

⁹	EMC Group Energy Purchase Amount

¹⁰	Blue Ridge Energy Purchase Amount / EMC Group Combined Energy Purchase Amount.

¹¹	Piedmont Energy Purchase Amount / EMC Group Combined Energy Purchase Amount.

¹²	Rutherford Energy Purchase Amount / EMC Group Combined Energy Purchase Amount.

- 3 -

Step 3

Calculate Duke Total Hourly Energy Charge = 113% of Duke Territorial Incremental Cost for electric energy delivered by Duke to the EMC Group for the Hour (3,000 kW * $0.10/kWh * 113% = $339.00)

Step 4

Calculate the individual EMC’s Allocated Share of the Duke Total Hourly Energy Charge.

Apply the percentages derived in Step 2 to the Duke Total Hourly Energy Charge.

BR ¹³

P ¹⁴

R ¹⁵

Sum ¹⁶

$ for energy delivered by Duke

101.70

67.80

169.50

339.00

These amounts are included in the Duke Hourly Energy Charge.

¹³	Blue Ridge Allocated Share of Duke Total Hourly Energy Charge.

¹⁴	Piedmont Allocated Share of Duke Total Hourly Energy Charge

¹⁵	Rutherford Allocated Share of Duke Total Hourly Energy Charge

¹⁶	Duke Total Hourly Energy Charge

- 4 -

B. Calculation of Blue Ridge, Piedmont and Rutherford Allocated Shares of the EMC Group Total Hourly Energy Credit

Step 5

Sum the energy deliveries by BR to Duke for all Intervals over the entire Hour (column 1). Repeat calculation for P and R (columns 2-3). Sum columns 1-3 (column 4). Sum the energy deliveries by EMC Group to Duke for all Intervals over the entire Hour (column 5).


Column number	1	2	3	4	5
	BR ¹⁷	P ¹⁸	R ¹⁹	Sum ²⁰	EMC Group ²¹
Energy delivered by Customer (kW)	4,500	5,000	4,500	14,000	7,000

Step 6

Calculate the percentage that each Customer contributed to the energy deliveries by Customers (Customer delivery / Sum of Customer deliveries)

BR ²²

P ²³

R ²⁴

Sum

Energy delivered by Customer

32.14

35.71

32.14

100.00

¹⁷	Blue Ridge Energy Credit Amount

¹⁸	Piedmont Energy Credit Amount

¹⁹	Rutherford Energy Credit Amount

²⁰	EMC Group Combined Energy Credit Amount

²¹	EMC Group Energy Credit Amount

²²	Blue Ridge Energy Credit Amount / EMC Group Combined Energy Credit Amount.

²³	Piedmont Energy Credit Amount / EMC Group Combined Energy Credit Amount.

²⁴	Rutherford Energy Credit Amount / EMC Group Combined Energy Credit Amount.

- 5 -

Step 7

Calculate the EMC Group Total Hourly Energy Credit = 90% of Duke Territorial Decremental Cost for electric energy delivered by the EMC Group to Duke for the Hour (7,000 kW * $0.10/kWh * 90% = $630)

Step 8

Calculate the EMC Allocated Share of the EMC Group Total Hourly Energy Credit

Apply the percentages derived in Step 6 to the EMC Group Total Hourly Energy Credit.

BR ²⁵

P ²⁶

R ²⁷

Sum ²⁸

$ for energy delivered by Customers

202.50

225.00

202.50

630.00

²⁵	Blue Ridge Allocated Share of EMC Group Total Hourly Energy Credit.

²⁶	Piedmont Allocated Share of EMC Group Total Hourly Energy Credit

²⁷	Rutherford Allocated Share of EMC Group Total Hourly Energy Credit

²⁸	EMC Group Total Hourly Energy Credit

- 6 -

C. Calculation of Blue Ridge, Piedmont and Rutherford Allocated Shares of the Inter-EMC Energy Charge

Step 9

Calculate the difference between the EMC Group Combined Energy Purchase Amount (sum determined in Step 1, column 4) and the EMC Group Energy Purchase Amount (aggregate calculated in Step 1, column 5).


Step 5, column 4 ²⁹		10,000
Step 5, column 5 ³⁰		-3,000

Difference		7,000

Step 10

Apply the percentages derived in Step 2 to the difference derived in Step 9.


	BR	P	R	Sum
Energy delivered by Duke	2,100	1,400	3,500	7,000

Step 11

Calculate Inter-EMC Transfer Price: Average of 113% of Duke Territorial Incremental Cost and 90% of Duke Territorial Decremental Cost, unless EMC Group Energy Purchase Amount or EMC Group Energy Credit Amount is zero. If EMC Group Energy Purchase Amount is zero, Inter-EMC Transfer Price is 101.50% of Duke Territorial Decremental Cost. If EMC Group Energy Credit Amount is zero, Inter-EMC Transfer Price is 101.50% of Duke Territorial Incremental Cost. In this example, Inter-EMC Transfer Price is average of $0.113/kWh and $0.09/kWh, or $0.1015/kWh.

²⁹	EMC Group Combined Energy Purchase Amount

³⁰	EMC Group Energy Purchase Amount

- 7 -

Step 12

Multiply the Inter-EMC Transfer Price times the amounts derived in Step 10.

BR ³¹

P ³²

R ³³

Sum

$ for Inter-EMC Charge

213.15

142.10

355.25

710.50

These amounts are included in the Duke Hourly Energy Charge

D. Calculation of Blue Ridge, Piedmont and Rutherford Allocated Shares of the Inter-EMC Energy Credit

Step 13

Calculate the EMC Group Combined Energy Credit Amount (difference between the sum determined in Step 5, column 4) and the EMC Group Credit Amount (aggregate calculated in Step 5, column 5).


Step 5, column 4 ³⁴		14,000
Step 5, column 5 ³⁵		-7,000

Difference		7,000

³¹	Blue Ridge Allocated Share of Inter-EMC Energy Charge

³²	Piedmont Allocated Share of Inter-EMC Energy Charge

³³	Rutherford Allocated Share of Inter-EMC Energy Charge

³⁴	EMC Group Combined Energy Credit Amount

³⁵	EMC Group Energy Credit Amount

- 8 -

Step 14

Apply the percentages derived in Step 6 to the difference derived in Step 13.

Sum

Energy delivered by Customer

2,250

2,500

2,250

7,000

Step 15

Muliply the Inter-EMC Transfer Price times the amounts derived in Step 14

BR ³⁶

P ³⁷

R ³⁸

Sum

$ for Inter-EMC Credit

228.38

253.75

228.38

710.50

III.

CHARGE/CREDIT SUMMATION FOR THE HOUR


		BR			P			R		Total
1.	Allocated Share of Duke Total Hourly Energy Ch. (Step 4)	$	101.70		$	67.80		$	169.50	$	339.00
2.	Allocated Share of Inter-EMC Energy Charge (Step 12)	$	213.15		$	142.10		$	355.25	$	710.50

3.	Subtotal (row 1 + row 2)	$	314.85		$	209.90		$	524.75	$	1,049.50

4.	Allocated Share of EMC Group Ttl Hourly En. Cr. (Step 8)	$	202.50		$	225.00		$	202.50	$	630.00
5.	Allocated Share of Inter-EMC Energy Credit (Step 15)	$	228.38		$	253.75		$	228.38	$	710.50

6.	Subtotal (row 4 + row 5)	$	430.88		$	478.75		$	430.88	$	1,340.50

7.	Total charge (credit) (row 3 – row 6)	$	(116.03	)	$	(268.85	)	$	93.88	$	(291.00	)

³⁶	Blue Ridge Allocated Share of Inter-EMC Energy Credit

³⁷	Piedmont Allocated Share of Inter-EMC Energy Credit

³⁸	Rutherford Allocated Share of Inter-EMC Energy Credit

- 9 -

Attachment 7-4

Example 2

Showing the Calculation of Blue Ridge, Piedmont and

Rutherford Allocated Shares of the Duke Total Hourly Energy Charge,

EMC Group Total Hourly Energy Credit, Inter-EMC Energy Charge and Inter-EMC Energy Credit

I.	ASSUMPTIONS:

Call and Put Signals during the Hour


	BR	P	R	EMC Group
Intervals 1-225 ³⁹ - Call Signal during each Interval (kW):	0	3,000	3,000	2,000
Intervals 1-225 - Put Signal during each Interval (kW)	4,000	0	0	0
Intervals 226-450 - Call Signal during each Interval (kW)	0	5,000	3,000	4,000
Intervals 226-450 - Put Signal during each Interval (kW)	4,000	0	0	0
Intervals 451-675 - Call Signal during each Interval (kW)	0	2,000	0	0
Intervals 451-675 - Put Signal during each Interval (kW)	2,000	0	0	0
Intervals 676-900 - Call Signal during each Interval (kW)	0	1,000	1,000	0
Intervals 676-900 - Put Signal during each Interval (kW)	4,000	0	0	2,000

³⁹

- 10 -

Energy deliveries during the Hour ⁴⁰


	BR	P	R	EMC Group
Hourly Energy Amount delivered from Duke - Intervals 1-225	0	750	750	500
Hourly Energy Amount delivered to Duke - Intervals 1-225	1,000	0	0	0
Hourly Energy Amount delivered from Duke - Intervals 226-450	0	1,250	750	1,000
Hourly Energy Amount delivered to Duke - Intervals 226-450	1,000	0	0	0
Hourly Energy Amount delivered from Duke - Intervals 451-675	0	500	0	0
Hourly Energy Amount delivered to Duke - Intervals 451-675	500	0	0	0
Hourly Energy Amount delivered from Duke - Intervals 676-900	0	250	250	0
Hourly Energy Amount delivered to Duke - Intervals 676-900	1,000	0	0	500

Incremental/Decremental Costs

Duke Territorial Incremental Cost: $0.10/kWh

Duke Territorial Decremental Cost: $0.10/kWh

II.

CALCULATIONS

Calculation of Blue Ridge, Piedmont and Rutherford Allocated Shares of the Duke Total Hourly Energy Charge

Step 1

⁴⁰	These numbers sum the four-second Call and Put Signals from Part I.A. For example, 3,000 kW delivered by Duke in each of the 225 four-second Intervals (15 minutes) equal 750 kWh (2,000 KW * 225 Intervals / 900 Intervals / Hour = 750 kWh).

- 11 -


Column number	1	2	3	4	5
	BR ⁴¹	P ⁴²	R ⁴³	Sum ⁴⁴	Aggregate EMC Group ⁴⁵
Energy delivered by Duke (kW)	0	2,750	1,750	4,500	1,500

Step 2

Calculate the percentage that each Customer contributed to the energy deliveries by Duke (Customer Buy / Sum of Customer Buys)

BR ⁴⁶

P ⁴⁷

R ⁴⁸

Sum

Energy delivered by Duke

0.00

61.11

38.89

100.00

⁴¹	Blue Ridge Energy Purchase Amount

⁴²	Piedmont Energy Purchase Amount

⁴³	Rutherford Energy Purchase Amount

⁴⁴	EMC Group Combined Energy Purchase Amount

⁴⁵	EMC Group Energy Purchase Amount

⁴⁶	Blue Ridge Energy Purchase Amount / EMC Group Combined Energy Purchase Amount.

⁴⁷	Piedmont Energy Purchase Amount / EMC Group Combined Energy Purchase Amount.

⁴⁸	Rutherford Energy Purchase Amount / EMC Group Combined Energy Purchase Amount.

- 12 -

Step 3

Calculate Duke Total Hourly Energy Charge = 113% of Duke Territorial Incremental Cost for electric energy delivered by Duke to the EMC Group for the Hour (1,500 kW * $0.10/kWh * 113% = $169.50)

Step 4

Calculate the individual EMC’s Allocated Share of the Duke Total Hourly Energy Charge.

Apply the percentages derived in Step 2 to the Duke Total Hourly Energy Charge.


	BR ⁴⁹	P ⁵⁰	R ⁵¹	Sum ⁵²
$ for energy delivered by Duke	$0.00	$103.58	$65.92	$169.50

These amounts are included in the Duke Hourly Energy Charge.

⁴⁹	Blue Ridge Allocated Share of Duke Total Hourly Energy Charge.

⁵⁰	Piedmont Allocated Share of Duke Total Hourly Energy Charge

⁵¹	Rutherford Allocated Share of Duke Total Hourly Energy Charge

⁵²	Duke Total Hourly Energy Charge

- 13 -

Calculation of Blue Ridge, Piedmont and Rutherford Allocated Shares of the EMC Group Total Hourly Energy Credit

Step 5


Column number	1	3	4	5	6
	BR ⁵³	P ⁵⁴	R ⁵⁵	Sum ⁵⁶	EMC Group ⁵⁷
Energy delivered by Customer (kW)	3,500	0	0	3,500	500

Step 6

Calculate the percentage that each Customer contributed to the energy deliveries by Customers (Customer delivery / Sum of Customer deliveries)

⁵³	Blue Ridge Energy Credit Amount

⁵⁴	Piedmont Energy Credit Amount

⁵⁵	Rutherford Energy Credit Amount

⁵⁶	EMC Group Combined Energy Credit Amount

⁵⁷	EMC Group Energy Credit Amount

- 14 -

BR ⁵⁸

P ⁵⁹

R ⁶⁰

Sum

Energy delivered by Customer

100.00

0.00

100.00

Step 7

Calculate the EMC Group Total Hourly Energy Credit = 90% of Duke Territorial Decremental Cost for electric energy delivered by the EMC Group to Duke for the Hour (500 kW * $0.10/kWh * 90% = $45)

Step 8

Calculate the EMC Allocated Share of the EMC Group Total Hourly Energy Credit

Apply the percentages derived in Step 6 to the EMC Group Total Hourly Energy Credit.


	BR ⁶¹	P ⁶²	R ⁶³	Sum ⁶⁴
$ for energy delivered by Customers	$45.00	$—	$—	$45.00

⁵⁸	Blue Ridge Energy Credit Amount / EMC Group Combined Energy Credit Amount.

⁵⁹	Piedmont Energy Credit Amount / EMC Group Combined Energy Credit Amount.

⁶⁰	Rutherford Energy Credit Amount / EMC Group Combined Energy Credit Amount.

⁶¹	Blue Ridge Allocated Share of EMC Group Total Hourly Energy Credit.

⁶²	Piedmont Allocated Share of EMC Group Total Hourly Energy Credit

⁶³	Rutherford Allocated Share of EMC Group Total Hourly Energy Credit

⁶⁴	EMC Group Total Hourly Energy Credit

- 15 -

Calculation of Blue Ridge, Piedmont and Rutherford Allocated Shares of the Inter-EMC Energy Charge

Step 9


Step 1, column 4 ⁶⁵		4,500
Step 1, column 5 ⁶⁶		-1,500

Difference		3,000

Step 10

Apply the percentages derived in Step 2 to the difference derived in Step 9.


	BR	P	R	Sum
Energy delivered by Duke	0	1,833	1,167	3,000

Step 11

⁶⁵	EMC Group Combined Energy Purchase Amount

⁶⁶	EMC Group Energy Purchase Amount

- 16 -

Credit Amount is zero, Inter-EMC Transfer Price is 101.50% of Duke Territorial Incremental Cost. In this example, Inter-EMC Transfer Price is average of $0.113/kWh and $0.09/kWh, or $0.1015/kWh.

Step 12

Multiply the Inter-EMC Transfer Price times the amounts derived in Step 10.


	BR ⁶⁷	P ⁶⁸	R ⁶⁹	Sum
$ for Inter-EMC Charge	$0.00	$186.08	$118.42	$304.50

Calculation of Blue Ridge, Piedmont and Rutherford Allocated Shares of the Inter-EMC Energy Credit

Step 13

Calculate the EMC Group Combined Energy Credit Amount (difference between the sum determined in Step 5, column 4) and the EMC Group Credit Amount (aggregate calculated in Step 5, column 5).


Step 5, column 4 ⁷⁰		3,500
Step 5, column 5 ⁷¹		- 500

Difference		3,000

⁶⁷	Blue Ridge Allocated Share of Inter-EMC Energy Charge

⁶⁸	Piedmont Allocated Share of Inter-EMC Energy Charge

⁶⁹	Rutherford Allocated Share of Inter-EMC Energy Charge

- 17 -

Step 14

Apply the percentages derived in Step 6 to the difference derived in Step 13.


	BR	P	R	Sum
Energy delivered by Customer	3,000	0	0	3,000

Step 15

Multiply the Inter-EMC Transfer Price times the amounts derived in Step 14

	BR ⁷²	P ⁷³	R ⁷⁴	Sum
$ for Inter-EMC Credit	$304.50	$0.00	$0.00	$304.50

⁷⁰	EMC Group Combined Energy Credit Amount

⁷¹	EMC Group Energy Credit Amount

⁷²	Blue Ridge Allocated Share of Inter-EMC Energy Credit

⁷³	Piedmont Allocated Share of Inter-EMC Energy Credit

⁷⁴	Rutherford Allocated Share of Inter-EMC Energy Credit

- 18

III.

CHARGE/CREDIT SUMMATION FOR THE HOUR


		BR			P		R		Total
1.	Allocated Share of Duke Total Hourly Energy Ch. (Step 4)	$	0.00		$	103.58	$	65.92	$	169.50
2.	Allocated Share of Inter-EMC Energy Charge (Step 12)	$	0.00		$	186.08	$	118.42	$	304.50

3.	Subtotal (row 1 + row 2)	$	0.00		$	289.67	$	184.33	$	474.00

4.	Allocated Share of EMC Group Ttl Hourly En. Cr. (Step 8)	$	45.00		$	0.00	$	0.00	$	45.00
5.	Allocated Share of Inter-EMC Energy Credit (Step 15)	$	304.50		$	0.00	$	0.00	$	304.50

6.	Subtotal (row 4 + row 5)	$	349.50		$	0.00	$	0.00	$	349.50

7.	Total charge (credit) (row 3 – row 6)	$	(349.50	)	$	289.67	$	184.33	$	124.50

- 19 -

Attachment 7-5

Example showing Calculations of

Piedmont Energy Purchase Amounts

and Piedmont Energy Credit Amount

This attachment provides an example showing the calculation of the Piedmont Energy Purchase Amount and Piedmont Energy Credit Amount for one Hour.


Four-second Interval Number *	A EMC’s Base Obligation (kW)	B EMC’s Native Load (kW)	C Call Signal (B-A where B>A) (kW)	D Call energy (C/900) (kWhs)		E Put Signal (A-B where A>B) (kW)	F Put energy (E/900) (kWhs)
1	100,000	102,000	2,000	2.2		—	—
2	100,000	101,000	1,000	1.1		—	—
3	100,000	100,000	—	—		—	—
4	100,000	99,000	—	—		1,000	1.1
5	100,000	98,000	—	—		2,000	2.2
6	100,000	97,000	—	—		3,000	3.3
7-895 ⁷⁵	100,000	100,000	—	—		—	—
896	100,000	98,000	—	—		2,000	2.2
897	100,000	99,000	—	—		1,000	1.1
898	100,000	100,000	—	—		—	—
899	100,000	101,000	1,000	1.1		—	—
900	100,000	102,000	2,000	2.2		—	—

Total				6.6	⁷⁶		9.9	⁷⁷

*	Interval numbers refer to the Intervals during the hour (e.g., Interval 1 is the first four seconds of the hour, Interval 2 is the next four seconds, etc.)

⁷⁵	To simplify this example, EMC’s Base Obligation and EMC’s Native Load are assumed to be equal during Intervals 6-895. In actual operation, the parties anticipate that these amounts will differ throughout the Hour.

⁷⁶	Piedmont Energy Purchase Amount

⁷⁷	Piedmont Energy Credit Amount

Attachment 7-6

Example showing Calculations of EMC Group Energy Purchase Amounts

and EMC Group Energy Credit Amount

This attachment provides an example showing the calculation of the EMC Group Energy Purchase Amount and EMC Group Energy Credit Amount for one Hour.


Four-second Interval Number *	A EMC Group Base Obligation (kW)	B EMC Group Native Load (kW)	C Call Signal (B-A where B>A) (kW)	D Call energy (C/900) (kWhs)		E Put Signal (A-B where A>B) (kW)	F Put energy (E/900) (kWhs)
1	400,000	408,000	8,000	8.8		—	—
2	400,000	404,000	4,000	4.4		—	—
3	400,000	400,000	—	—		—	—
4	400,000	396,000	—	—		4,000	4.4
5	400,000	392,000	—	—		8,000	8.8
6	400,000	388,000	—	—		12,000	13.2
7-895 ⁷⁸	400,000	400,000	—	—		—	—
896	400,000	392,000	—	—		8,000	8.8
897	400,000	396,000	—	—		4,000	4.4
898	400,000	400,000	—	—		—	—
899	400,000	404,000	4,000	4.4		—	—
900	400,000	408,000	8,000	8.8		—	—

Total				26.4	⁷⁹		39.6	⁸⁰

*	Interval numbers refer to the Intervals during the hour (e.g., Interval 1 is the first four seconds of the hour, Interval 2 is the next four seconds, etc.)

⁷⁸	To simplify this example, the EMC Group’s Base Obligation and the EMC Group’s Native Load are assumed to be equal during Intervals 6-895. In actual operation, the Parties anticipate that these amounts will differ throughout the Hour.

⁷⁹	EMC Group Energy Purchase Amount

⁸⁰	EMC Group Energy Credit Amount

Attachment 7-7

Example showing the calculation of

Monthly Billing Demand under Section 7.2.6.3.2

The purpose of this attachment is to provide an example showing the calculation of the Monthly Billing Demand under Section 7.2.6.3.2 of the Agreement.

I. Assumptions:


		Day	Hour	Load (MW)
1.	Highest Hourly Duke Schedule 1 Demand during 2007	7-25-07	5:00-6:00 p.m.	17,000
2.	2 ^nd highest Hourly Duke Schedule 1 Demand during 2007	7-25-07	6:00-7:00 p.m.	16,975
3.	3 ^rd highest Hourly Duke Schedule 1 Demand during 2007	7-25-07	4:00-5:00 p.m.	16,950
4.	4 ^th highest Hourly Duke Schedule 1 Demand during 2007	7-25-07	3:00-4:00 p.m.	16,925
5.	5 ^th highest Hourly Duke Schedule 1 Demand during 2007	7-24-07	5:00-6:00 p.m.	16,900
6.	6 ^th highest Hourly Duke Schedule 1 Demand during 2007	7-24-07	6:00-7:00 p.m.	16,875
7.	7 ^th highest Hourly Duke Schedule 1 Demand during 2007	7-24-07	4:00-5:00 p.m.	16,850
8.	8 ^th highest Hourly Duke Schedule 1 Demand during 2007	7-24-07	3:00-4:00 p.m.	16,825
9.	9 ^th highest Hourly Duke Schedule 1 Demand during 2007	8-1-07	5:00-6:00 p.m.	16,800
10.	10 ^th highest Hourly Duke Schedule 1 Demand during 2007	8-1-07	6:00-7:00 p.m.	16,775
11.	11 ^th highest Hourly Duke Schedule 1 Demand during 2007	8-1-07	4:00-5:00 p.m.	16,750
12.	12 ^th highest Hourly Duke Schedule 1 Demand during 2007	8-1-07	3:00-4:00 p.m.	16,725
13.	13 ^th highest Hourly Duke Schedule 1 Demand during 2007	7-26-07	5:00-6:00 p.m.	16,700
14.	14 ^th highest Hourly Duke Schedule 1 Demand during 2007	7-26-07	6:00-7:00 p.m.	16,675
15.	15 ^th highest Hourly Duke Schedule 1 Demand during 2007	6-26-07	4:00-5:00 p.m.	16,650
16.	16 ^th highest Hourly Duke Schedule 1 Demand during 2007	7-26-07	4:00-5:00 p.m.	16,625
17.	17 ^th highest Hourly Duke Schedule 1 Demand during 2007	7-24-07	3:00-4:00 p.m.	16,600
18.	18 ^th highest Hourly Duke Schedule 1 Demand during 2007	1-18-07	9:00-10:00 a.m.	16,575
19.	19 ^th highest Hourly Duke Schedule 1 Demand during 2007	1-18-07	10:00-11:00 a.m.	16,550
20.	20 ^th highest Hourly Duke Schedule 1 Demand during 2007	8-2-07	4:00-5:00 p.m.	16,525


		Day	Hour	Load (MW)
21.	21 ^st highest Hourly Duke Schedule 1 Demand during 2007	8-2-07	3:00-4:00 p.m.	16,500
22.	22 ^nd highest Hourly Duke Schedule 1 Demand during 2007	8-2-07	5:00-6:00 p.m.	16,475
23.	23 ^rd highest Hourly Duke Schedule 1 Demand during 2007	8-2-07	6:00-7:00 p.m.	16,450
24.	24 ^th highest Hourly Duke Schedule 1 Demand during 2007	7-18-07	3:00-4:00 p.m.	16,425
25.	25 ^th highest Hourly Duke Schedule 1 Demand during 2007	7-18-07	4:00-5:00 p.m.	16,400
26.	26 ^th highest Hourly Duke Schedule 1 Demand during 2007	7-18-07	2:00-3:00 p.m.	16,375
27.	27 ^th highest Hourly Duke Schedule 1 Demand during 2007	7-18-07	1:00-2:00 p.m.	16,350
28.	28 ^th highest Hourly Duke Schedule 1 Demand during 2007	7-17-07	5:00-6:00 p.m.	16,325
29.	29 ^th highest Hourly Duke Schedule 1 Demand during 2007	7-17-07	6:00-7:00 p.m.	16,300
30.	30 ^th highest Hourly Duke Schedule 1 Demand during 2007	7-17-07	4:00-5:00 p.m.	16,325

II.	Calculation of Monthly Billing Demand for 2007:

The twenty (20) highest load hours during July-August are hours 1-14, 16-17 and 20-23.


No. from Part I	Day	Hour	EMC Native Load (kW)	EMC Base Obligation (kW)	EMC Native Load minus EMC Base Obligation (kW)
1.	7-25-07	5:00-6:00 p.m.	100,000	80,000	20,000
2.	7-25-07	6:00-7:00 p.m.	102,000	80,000	22,000
3.	7-25-07	4:00-5:00 p.m.	104,000	80,000	24,000
4.	7-25-07	3:00-4:00 p.m.	106,000	80,000	26,000
5.	7-24-07	5:00-6:00 p.m.	104,000	80,000	24,000
6.	7-24-07	6:00-7:00 p.m.	102,000	79,000	23,000
7.	7-24-07	4:00-5:00 p.m.	100,000	79,000	21,000
8.	7-24-07	3:00-4:00 p.m.	100,000	79,000	21,000
9.	8-1-07	5:00-6:00 p.m.	100,000	79,000	21,000
10.	8-1-07	6:00-7:00 p.m.	100,000	78,000	22,000
11.	8-1-07	4:00-5:00 p.m.	99,000	78,000	21,000

- 2 -


No. from Part I	Day	Hour	EMC Native Load (kW)	EMC Base Obligation (kW)	EMC Native Load minus EMC Base Obligation (kW)
12.	8-1-07	3:00-4:00 p.m.	99,000	78,000	21,000
13.	7-26-07	5:00-6:00 p.m.	99,000	100,000	0
14.	7-26-07	6:00-7:00 p.m.	99,000	100,000	0
16.	7-26-07	4:00-5:00 p.m.	98,000	100,000	0
17.	7-24-07	3:00-4:00 p.m.	98,000	100,000	0
20.	8-2-07	4:00-5:00 p.m.	98,000	100,000	0
21.	8-2-07	3:00-4:00 p.m.	98,000	100,000	0
22.	8-2-07	5:00-6:00 p.m.	98,000	100,000	0
23.	8-2-07	6:00-7:00 p.m.	98,000	100,000	0

	TOTAL				266,000

	AVERAGE				13,300 ⁸¹

⁸¹	Monthly Billing Demand for each Month during 2007.

- 3 -

Attachment 7-8

Examples showing the calculation of

Monthly Billing Demand under Section 7.3.2.2

The purpose of this attachment is to provide examples showing the calculation of the Monthly Billing Demand under Section 7.3.2.2 of the Agreement.

Example A

I. Assumptions:


		Day	Hour	Load (MW)
1.	Highest Hourly Duke Schedule 1 Demand during 2012	7-25-12	5:00-6:00 p.m.	17,000
2.	2 ^nd highest Hourly Duke Schedule 1 Demand during 2012	7-25-12	6:00-7:00 p.m.	16,975
3.	3 ^rd highest Hourly Duke Schedule 1 Demand during 2012	7-25-12	4:00-5:00 p.m.	16,950
4.	4 ^th highest Hourly Duke Schedule 1 Demand during 2012	7-25-12	3:00-4:00 p.m.	16,925
5.	5 ^th highest Hourly Duke Schedule 1 Demand during 2012	7-24-12	5:00-6:00 p.m.	16,900
6.	6 ^th highest Hourly Duke Schedule 1 Demand during 2012	7-24-12	6:00-7:00 p.m.	16,875
7.	7 ^th highest Hourly Duke Schedule 1 Demand during 2012	7-24-12	4:00-5:00 p.m.	16,850
8.	8 ^th highest Hourly Duke Schedule 1 Demand during 2012	7-24-12	3:00-4:00 p.m.	16,825
9.	9 ^th highest Hourly Duke Schedule 1 Demand during 2012	8-1-12	5:00-6:00 p.m.	16,800
10.	10 ^th highest Hourly Duke Schedule 1 Demand during 2012	8-1-12	6:00-7:00 p.m.	16,775
11.	11 ^th highest Hourly Duke Schedule 1 Demand during 2012	8-1-12	4:00-5:00 p.m.	16,750
12.	12 ^t ^h highest Hourly Duke Schedule 1 Demand during 2012	8-1-12	3:00-4:00 p.m.	16,725
13.	13 ^th highest Hourly Duke Schedule 1 Demand during 2012	7-26-12	5:00-6:00 p.m.	16,700
14.	14 ^th highest Hourly Duke Schedule 1 Demand during 2012	7-26-12	6:00-7:00 p.m.	16,675
15.	15 ^th highest Hourly Duke Schedule 1 Demand during 2012	6-26-12	4:00-5:00 p.m.	16,650
16.	16 ^th highest Hourly Duke Schedule 1 Demand during 2012	7-26-12	4:00-5:00 p.m.	16,625
17.	17 ^th highest Hourly Duke Schedule 1 Demand during 2012	7-24-12	3:00-4:00 p.m.	16,600
18.	18 ^th highest Hourly Duke Schedule 1 Demand during 2012	1-18-12	9:00-10:00 a.m.	16,575
19.	19 ^th highest Hourly Duke Schedule 1 Demand during 2012	1-18-12	10:00-11:00 a.m.	16,550


		Day	Hour	Load (MW)
20.	20 ^th highest Hourly Duke Schedule 1 Demand during 2012	8-2-12	4:00-5:00 p.m.	16,525
21.	21 ^st highest Hourly Duke Schedule 1 Demand during 2012	8-2-12	3:00-4:00 p.m.	16,500
22.	22 ^nd highest Hourly Duke Schedule 1 Demand during 2012	8-2-12	5:00-6:00 p.m.	16,475
23.	23 ^rd highest Hourly Duke Schedule 1 Demand during 2012	8-2-12	6:00-7:00 p.m.	16,450
24.	24 ^th highest Hourly Duke Schedule 1 Demand during 2012	7-18-12	3:00-4:00 p.m.	16,425
25.	25 ^th highest Hourly Duke Schedule 1 Demand during 2012	7-18-12	4:00-5:00 p.m.	16,400
26.	26 ^th highest Hourly Duke Schedule 1 Demand during 2012	7-18-12	2:00-3:00 p.m.	16,375
27.	27 ^th highest Hourly Duke Schedule 1 Demand during 2012	7-18-12	1:00-2:00 p.m.	16,350
28.	28 ^th highest Hourly Duke Schedule 1 Demand during 2012	7-17-12	5:00-6:00 p.m.	16,325
29.	29th highest Hourly Duke Schedule 1 Demand during 2012	7-17-12	6:00-7:00 p.m.	16,300
30.	30 ^th highest Hourly Duke Schedule 1 Demand during 2012	7-17-12	4:00-5:00 p.m.	16,325

Annual Planning Period is May through September

II. Calculation of Monthly Billing Demand for 2012:

The twenty (20) highest load hours during the Summer Period are hours 1-17 and 20-22


No. from Part I	Day	Hour	EMC Native Load (kW)	EMC Partial Requirements Resources (kW)	EMC Native Load minus EMC Partial Requirements Resources (kW)
1.	7-25-12	5:00-6:00 p.m.	120,000	100,000	20,000
2.	7-25-12	6:00-7:00 p.m.	120,000	100,000	20,000
3.	7-25-12	4:00-5:00 p.m.	120,000	100,000	20,000
4.	7-25-12	3:00-4:00 p.m.	120,000	100,000	20,000
5.	7-24-12	5:00-6:00 p.m.	115,000	100,000	15,000
6.	7-24-12	6:00-7:00 p.m.	115,000	100,000	15,000
7.	7-24-12	4:00-5:00 p.m.	115,000	100,000	15,000

- 2 -


No. from Part I	Day	Hour	EMC Native Load (kW)	EMC Partial Requirements Resources (kW)	EMC Native Load minus EMC Partial Requirements Resources (kW)
8.	7-24-12	3:00-4:00 p.m.	115,000	100,000	15,000
9.	8-1-12	5:00-6:00 p.m.	110,000	100,000	10,000
10.	8-1-12	6:00-7:00 p.m.	110,000	100,000	10,000
11.	8-1-12	4:00-5:00 p.m.	110,000	100,000	10,000
12.	8-1-12	3:00-4:00 p.m.	110,000	100,000	10,000
13.	7-26-12	5:00-6:00 p.m.	105,000	100,000	5,000
14.	7-26-12	6:00-7:00 p.m.	105,000	100,000	5,000
15.	6-26-12	4:00-5:00 p.m.	105,000	100,000	5,000
16.	7-26-12	4:00-5:00 p.m.	105,000	100,000	5,000
17.	7-24-12	3:00-4:00 p.m.	100,000	100,000	0
20.	8-2-12	4:00-5:00 p.m.	100,000	100,000	0
21.	8-2-12	3:00-4:00 p.m.	95,000	100,000	0
22.	8-2-12	5:00-6:00 p.m.	95,000	100,000	0

	TOTAL				200,000

	AVERAGE				10,000 ⁸²

Example B

I. Assumptions:


		Day	Hour	Load (MW)
1.	Highest Hourly Duke Schedule 1 Demand during 2012	1-25-12	7:00-8:00 a.m.	17,000
2.	2 ^nd highest Hourly Duke Schedule 1 Demand during 2012	1-25-12	8:00-9:00 a.m.	16,975

⁸²	Monthly Billing Demand for each Month during 2012.

- 3 -


		Day	Hour	Load (MW)
3.	3 ^rd highest Hourly Duke Schedule 1 Demand during 2012	1-25-12	9:00-10:00 a.m.	16,950
4.	4 ^th highest Hourly Duke Schedule 1 Demand during 2012	1-25-12	10:00-11:00 a.m.	16,925
5.	5 ^th highest Hourly Duke Schedule 1 Demand during 2012	1-24-12	7:00-8:00 a.m.	16,900
6.	6 ^th highest Hourly Duke Schedule 1 Demand during 2012	1-24-12	8:00-9:00 a.m.	16,875
7.	7 ^th highest Hourly Duke Schedule 1 Demand during 2012	1-24-12	9:00-10:00 a.m.	16,850
8.	8 ^th highest Hourly Duke Schedule 1 Demand during 2012	1-24-12	10:00-11:00 a.m.	16,825
9.	9 ^th highest Hourly Duke Schedule 1 Demand during 2012	2-1-12	7:00-8:00 a.m.	16,800
10.	10 ^th highest Hourly Duke Schedule 1 Demand during 2012	2-1-12	8:00-9:00 a.m.	16,775
11.	11 ^th highest Hourly Duke Schedule 1 Demand during 2012	2-1-12	9:00-10:00 a.m.	16,750
12.	12 ^th highest Hourly Duke Schedule 1 Demand during 2012	2-1-12	10:00-11:00 a.m.	16,725
13.	13 ^th highest Hourly Duke Schedule 1 Demand during 2012	12-21-12	8:00-9:00 a.m.	16,700
14.	14 ^th highest Hourly Duke Schedule 1 Demand during 2012	12-21-12	9:00-10:00 a.m.	16,675
15.	15 ^th highest Hourly Duke Schedule 1 Demand during 2012	12-21-12	10:00-11:00 a.m.	16,650
16.	16 ^th highest Hourly Duke Schedule 1 Demand during 2012	7-26-12	4:00-5:00 p.m.	16,625
17.	17 ^th highest Hourly Duke Schedule 1 Demand during 2012	7-24-12	3:00-4:00 p.m.	16,600
18.	18 ^th highest Hourly Duke Schedule 1 Demand during 2012	2-2-12	7:00-8:00 a.m.	16,575
19.	19 ^th highest Hourly Duke Schedule 1 Demand during 2012	2-2-12	8:00-9:00 a.m.	16,550
20.	20 ^th highest Hourly Duke Schedule 1 Demand during 2012	2-2-12	9:00-10:00 a.m.	16,525
21.	21 ^st highest Hourly Duke Schedule 1 Demand during 2012	2-2-12	10:00-11:00 a.m.	16,500
22.	22 ^nd highest Hourly Duke Schedule 1 Demand during 2012	1-18-12	9:00-10:00 a.m.	16,475
23.	23 ^rd highest Hourly Duke Schedule 1 Demand during 2012	1-18-12	10:00-11:00 a.m.	16,450
24.	24 ^th highest Hourly Duke Schedule 1 Demand during 2012	1-18-12	7:00-8:00 a.m.	16,425
25.	25 ^th highest Hourly Duke Schedule 1 Demand during 2012	1-18-12	8:00-9:00 a.m.	16,400
26.	26 ^th highest Hourly Duke Schedule 1 Demand during 2012	1-18-12	6:00-7:00 a.m.	16,375
27.	27 ^th highest Hourly Duke Schedule 1 Demand during 2012	1-18-12	11:00 a.m.-12:00 p.m.	16,350
28.	28 ^th highest Hourly Duke Schedule 1 Demand during 2012	1-17-12	8:00-9:00 a.m.	16,325
29.	29 ^th highest Hourly Duke Schedule 1 Demand during 2012	1-17-12	9:00-10:00 a.m.	16,300
30.	30 ^th highest Hourly Duke Schedule 1 Demand during 2012	1-17-12	10:00-11:00 a.m.	16,325
31.	Highest Hourly Duke Schedule 1 Demand during 2011	1-23-11	7:00-8:00 a.m.	17,000

- 4 -


		Day	Hour	Load (MW)
32.	2 ^nd highest Hourly Duke Schedule 1 Demand during 2011	1-23-11	8:00-9:00 a.m.	16,975
33.	3 ^rd highest Hourly Duke Schedule 1 Demand during 2011	1-23-11	9:00-10:00 a.m.	16,950
34.	4 ^th highest Hourly Duke Schedule 1 Demand during 2011	1-23-11	10:00-11:00 a.m.	16,925
35.	5 ^th highest Hourly Duke Schedule 1 Demand during 2011	1-18-11	7:00-8:00 a.m.	16,900
36.	6 ^th highest Hourly Duke Schedule 1 Demand during 2011	1-18-11	8:00-9:00 a.m.	16,875
37.	7 ^th highest Hourly Duke Schedule 1 Demand during 2011	1-18-11	9:00-10:00 a.m.	16,850
38.	8 ^th highest Hourly Duke Schedule 1 Demand during 2011	1-18-11	10:00-11:00 a.m.	16,825
39.	9 ^th highest Hourly Duke Schedule 1 Demand during 2011	2-4-11	7:00-8:00 a.m.	16,800
40.	10 ^th highest Hourly Duke Schedule 1 Demand during 2011	2-4-11	8:00-9:00 a.m.	16,775
41.	11 ^th highest Hourly Duke Schedule 1 Demand during 2011	2-4-11	9:00-10:00 a.m.	16,750
42.	12 ^th highest Hourly Duke Schedule 1 Demand during 2011	2-4-11	10:00-11:00 a.m.	16,725
43.	13 ^th highest Hourly Duke Schedule 1 Demand during 2011	1-28-11	8:00-9:00 a.m.	16,700
44.	14 ^th highest Hourly Duke Schedule 1 Demand during 2011	1-28-11	9:00-10:00 a.m.	16,675
45.	15 ^th highest Hourly Duke Schedule 1 Demand during 2011	12-15-11	9:00-10:00 a.m.	16,650
46.	16 ^th highest Hourly Duke Schedule 1 Demand during 2011	12-16-11	9:00-10:00 a.m.	16,625
47.	17 ^th highest Hourly Duke Schedule 1 Demand during 2011	12-15-11	10:00-11:00 a.m.	16,600
48.	18 ^th highest Hourly Duke Schedule 1 Demand during 2011	7-18-11	5:00-6:00 p.m.	16,575
49.	19 ^th highest Hourly Duke Schedule 1 Demand during 2011	7-18-11	6:00-7:00 p.m.	16,550
50.	20 ^th highest Hourly Duke Schedule 1 Demand during 2011	7-18-11	4:00-5:00 p.m.	16,525
51.	21 ^st highest Hourly Duke Schedule 1 Demand during 2011	7-18-11	3:00-4:00 p.m.	16,500
52.	22 ^nd highest Hourly Duke Schedule 1 Demand during 2011	1-18-11	11:00 a.m.-12:00 p.m.	16,475
53.	23 ^rd highest Hourly Duke Schedule 1 Demand during 2011	1-18-11	6:00-7:00 a.m.	16,450
54.	24 ^th highest Hourly Duke Schedule 1 Demand during 2011	2-5-11	8:00-9:00 a.m.	16,425
55.	25 ^th highest Hourly Duke Schedule 1 Demand during 2011	2-5-11	9:00-10:00 a.m.	16,400
56.	26 ^th highest Hourly Duke Schedule 1 Demand during 2011	1-20-11	8:00-9:00 a.m.	16,375
57.	27 ^th highest Hourly Duke Schedule 1 Demand during 2011	1-20-11	9:00-10:00 a.m.	16,350
58.	28 ^th highest Hourly Duke Schedule 1 Demand during 2011	1-21-11	7:00-8:00 a.m.	16,325
59.	29 ^th highest Hourly Duke Schedule 1 Demand during 2011	1-21-11	8:00-9:00 a.m.	16,300
60.	30 ^th highest Hourly Duke Schedule 1 Demand during 2011	1-21-11	9:00-10:00 a.m.	16,325

- 5 -

Annual Planning Period is October through April

The twenty (20) highest load hours during the Winter Period are hours 1-12 and 18-22 in 2012 and hours 45-47 in 2011.

II. Calculation of Monthly Billing Demand for 2012:


No. from Part I	Day	Hour	EMC Native Load (kW)	EMC Partial Requirements Resources (kW)	EMC Native Load minus EMC Partial Requirements Resources (kW)
1.	1-25-12	7:00-8:00 a.m.	120,000	100,000	20,000
2.	1-25-12	8:00-9:00 a.m.	120,000	100,000	20,000
3.	1-25-12	9:00-10:00 a.m.	120,000	100,000	20,000
4.	1-25-12	10:00-11:00 a.m.	120,000	100,000	20,000
5.	1-24-12	7:00-8:00 a.m.	115,000	100,000	15,000
6.	1-24-12	8:00-9:00 a.m.	115,000	100,000	15,000
7.	1-24-12	9:00-10:00 a.m.	115,000	100,000	15,000
8.	1-24-12	10:00-11:00 a.m.	115,000	100,000	15,000
9.	2-1-12	7:00-8:00 a.m.	110,000	100,000	10,000
10.	2-1-12	8:00-9:00 a.m.	110,000	100,000	10,000
11.	2-1-12	9:00-10:00 a.m.	110,000	100,000	10,000
12.	2-1-12	10:00-11:00 a.m.	110,000	100,000	10,000
45.	12-15-11	9:00-10:00 a.m.	105,000	100,000	5,000
46.	12-16-11	9:00-10:00 a.m.	105,000	100,000	5,000
47.	12-15-11	9:00-10:00 a.m.	105,000	100,000	5,000
18.	2-2-12	7:00-8:00 a.m.	105,000	100,000	5,000
19.	2-2-12	8:00-9:00 a.m.	100,000	100,000	0
20.	2-2-12	9:00-10:00 a.m.	100,000	100,000	0
21.	2-2-12	10:00-11:00 a.m.	95,000	100,000	0
22.	1-18-12	9:00-10:00 a.m.	95,000	100,000	0

	TOTAL				200,000

	AVERAGE				10,000 ⁸³

⁸³	Monthly Billing Demand for each Month during 2012.

- 6 -

ATTACHMENT 7-9

Demand Rate Adjustment Percentage and Annual Percentage

This attachment provides the formulas to be used for calculating the Demand Rate Adjustment Percentage and Annual Percentage for each calendar year beginning January 1, 2011.

The Demand Rate Adjustment Percentage shall equal the Production Capacity Revenue Requirement Adjustment divided by the Original Production Capacity Revenue Requirement, but not less than zero.

Where

Production Capacity Revenue Requirement Adjustment = (Annual Percentage – 4%) * (Original Production Capacity Revenue Requirement + Original Energy Revenue Requirement)

And

Annual Percentage shall equal the product of the System Gross Plant Difference and the Fixed Charge Rate, divided by the sum of Original Production Capacity Revenue Requirement and Original Energy Revenue Requirement. For purposes of calculating the Production Capacity Revenue Requirement Adjustment, the Annual Percentage shall be a maximum of 10%.

System Gross Plant Difference shall equal EMC Plant in Service less NC Retail Plant in Service. (May be positive or negative.) System Gross Plant Difference shall be decreased as necessary to eliminate differences between EMC Plant in Service and NC Retail Plant in Service related to timing or method of recovery of plant costs (e.g., plant differences due to recovery of construction period financing costs through inclusion of construction work in progress in rate base).

Fixed Charge Rate shall equal 10%.

EMC Plant in Service shall equal the average of the total ending balance of Production Plant, General Plant and Intangible Plant according to Schedule 1 of this Agreement, for the calendar year for which the Production Capacity Revenue Requirement calculation is prepared and total ending balance of Production Plant, General Plant and Intangible Plant according to Schedule 1 of this Agreement for the previous calendar year calculation of the Production Capacity Revenue Requirement.

NC Retail Plant in Service shall equal the sum of Duke Power Retail Plant in Service and Nantahala Retail Plant in Service, which shall be determined from Company records supporting the total Electric Plant in Service amount on Schedule 3 of NCUC Form E.S.-1 for the 12 month calendar period corresponding to the Production Capacity Revenue Requirement calculation used for calculating the EMC Plant in Service.

Duke Power Retail Plant in Service shall equal the average of the two December balances for the total of Production, General and Intangible plant amounts included in the total Electric Plant in Service monthly amounts shown on Schedule 3 of NCUC Form E.S.-1 for Duke Power.

Nantahala Retail Plant in Service shall equal the average of the two December balances for the total of Production, General and Intangible plant amounts included in the total Electric Plant in Service monthly amounts shown on Schedule 3 of NCUC Form E.S.-1 for Nantahala Power & Light.

Original Production Capacity Revenue Requirement shall equal the Production Capacity Revenue Requirement before consideration of any adjustments pursuant to Section 7.3.2.3 of the Agreement.

Original Energy Revenue Requirement shall equal the sum of F for purposes of calculating the Fuel Rate in Schedule 1 and Variable Non-Fuel Production Operation and Maintenance Expense for purposes of calculating the Variable O&M Rate in Schedule 1.

- 2 -

Attachment 7-10

Example of Demand Rate Adjustment Percentage and Annual Percentage

Note: EMC and NC Retail Plant in Service values are actuals for 2004.

CASE WITH NO ADJUSTMENT WARRANTED—


		NC Retail		EMC
1	Demand Rev Req Unadjusted			$	1,774,603
2	Energy Rev Req			$	1,235,341
3	Total Unadjusted Rev Req for EMC Rate Calcs			$	3,009,944		(Line 1 + Line 2)
4	Actual Gross Plant (“timing” adjusted)	$	11,509,514	$	11,509,514		NC Retail = Attachment 7-10, Page 4, Line 10
5	System Gross Plant Difference			$	—		(EMC Line 4 - NC Line 4)
6	Levelized FCR				0.100
7	Estimated Impact on Demand Rev Req			$	—		(Line 6 x Line 5)
8	Annual Percentage				0.00	%	(Line 7 / Line 3) No adjustment occurs since below 4% impact

Note: EMC Plant in Service values are actuals for 2004, but NC Retail Plant in Service values have been reduced for purpose of demonstration.

CASE WITH NO ADJUSTMENT WARRANTED—


		NC Retail		EMC
1	Demand Rev Req Unadjusted			$	1,774,603
2	Energy Rev Req			$	1,235,341
3	Total Unadjusted Rev Req for EMC Rate Calcs			$	3,009,944		(Line 1 + Line 2)
4	Actual Gross Plant (“timing” adjusted)	$	10,618,079	$	11,509,514		NC Retail = Attachment 7-10, Page 4, Line 10
5	System Gross Plant Difference			$	891,435		(EMC Line 4 - NC Line 4)
6	Levelized FCR				0.100
7	Estimated Impact on Demand Rev Req			$	89,143		(Line 6 x Line 5)
8	Annual Percentage				2.96	%	(Line 7 / Line 3) No adjustment occurs since below 4% impact

ADJUSTMENT WARRANTED


		NC Retail		EMC
1	Demand Rev Req Unadjusted			$	1,774,603
2	Energy Rev Req			$	1,235,341
3	Total Unadjusted Rev Req for EMC Rate Calcs			$	3,009,944		(Line 1 + Line 2)
4	Actual Gross Plant	$	9,729,655	$	11,509,514
5	System Gross Plant Difference			$	1,779,859		(EMC Line 4 - NC Line 4)
6	Levelized FCR				0.100
7	Estimated Impact on Demand Rev Req			$	177,986		(Line 6 x Line 5)
8	Annual Percentage				5.91	%	(Line 7 / Line 3) Since Annual Percentage is in excess of 4%, adjustment to Demand Rate is needed.
9	Demand Rate Adjustment Percentage				3.24	%	[(Line 8 - 4%) x Line 3] / Line 1
10	Demand Rate per Section 7.3.2.1			$	117.53
11	Demand Rate as adjusted per Section 7.3.2.3			$	113.72		Line 10 x (100% - Line 9)

- 2 -

ADJUSTMENT WARRANTED (but limited)


		NC Retail		EMC
1	Demand Rev Req Unadjusted			$	1,774,603
2	Energy Rev Req			$	1,235,341
3	Total Unadjusted Rev Req for EMC Rate Calcs			$	3,009,944		(Line 1 + Line 2)
4	Actual Gross Plant	$	8,368,409	$	11,509,514
5	System Gross Plant Difference			$	3,141,105		(EMC Line 4 - NC Line 4)
6	Levelized FCR				0.100
7	Estimated Impact on Demand Rev Req			$	314,110		(Line 6 x Line 5)
8	Annual Percentage				10.44	%	(Line 7 / Line 3) Since Annual Percentage is in excess of 4%, adjustment to Demand Rate is needed, but is limited to maximum of 6% of total unadjusted revenue requirements.
9	Demand Rate Adjustment Percentage				10.18	%	[(Line 8* - 4%) x Line 3] / Line 1
10	Demand Rate per Section 7.3.2.1			$	117.53
11	Demand Rate as adjusted per Section 7.3.2.3			$	105.57		Line 10 x (100% - Line 9)

*	maximum of 10%

- 3 -

(Amounts from Quarterly NCUC Form E.S.-1, Schedule 3, for 12ME 2004)


	(Dollars in thousands)	System Gross Electric Plant in Service for Determination of NC Retail Plant in Service
		Duke Power		Nantahala		Total NC Retail
		Beginning	Ending	Beginning	Ending	Beginning	Ending	Average
1	Plant in Service	18,980,402	19,683,592	324,710	334,880	19,305,112	20,018,472	19,661,792
	Components (data from Company records):
2	Production Plant	9,257,448	9,666,832	39,399	39,263	9,296,847	9,706,095	9,501,471
3	Nuclear Fuel (gross)	816,874	769,178			816,874	769,178	793,026
4	Total Production Plant	10,074,322	10,436,010	39,399	39,263	10,113,721	10,475,273	10,294,497
5	Transmission Plant	1,745,408	1,819,243	92,489	91,335	1,837,897	1,910,578	1,874,238
6	Distribution Plant	5,978,416	6,312,889	168,040	181,129	6,146,456	6,494,018	6,320,237
7	General Plant	973,070	902,246	20,232	18,603	993,302	920,849	957,076
8	Intangible Plant	209,186	213,204	4,550	4,550	213,736	217,754	215,745
9	Total (ties to Line 1)	18,980,402	19,683,592	324,710	334,880	19,305,112	20,018,472	19,661,792

10	Total of Production/General/Intangible Plant for use in Annual Percentage calculation					11,320,759	11,613,876	11,467,318


	(Dollars in thousands)	NC Retail Plant in Service	EMC Plant in Service - Amounts from Schedule 1 for 2004			EMC Plant in Service	System Gross Plant Difference	Adjustment for Timing Difference	Adjusted System Gross Plant Difference
			Beginning	Ending	Average
1	Plant in Service
	Components (data from Company records):
2	Production Plant	9,501,471	9,339,044	9,748,291	9,543,668	9,543,668	42,197	42,197	—
3	Nuclear Fuel (gross)	793,026	816,874	769,178	793,026	793,026	—		—
4	Total Production Plant	10,294,497	10,155,918	10,517,469	10,336,694	10,336,694	42,197	42,197	—
5	Transmission Plant
6	Distribution Plant
7	General Plant	957,076	993,303	920,849	957,076	957,076	—		—
8	Intangible Plant	215,745	213,736	217,753	215,745	215,745	—		—
9	Total (ties to Line 1)
10	Total of Production/General/Intangible Plant for use in Annual Percentage calculation	11,467,318	11,362,957	11,656,071	11,509,517	11,509,515	42,197	42,197

- 4 -

Attachment 8-1

(Part I of II)

TERMS AND CONDITIONS

FOR THE SCHEDULING OF POWER

SUPPLIED BY NORTH CAROLINA

ELECTRIC MEMBERSHIP CORPORATION

TO ITS INDEPENDENT MEMBERS

All NCEMC Committed Resources associated with the Wholesale Power Supply Agreement between the Seller and the Buyer are governed by and subject to all of the terms and conditions in this Exhibit, unless a specific Resource Summary Attachment explicitly provides otherwise. Unless defined in this Exhibit, all capitalized terms used herein shall have the respective meanings set forth as Article One of the Wholesale Power Supply Agreement.

General Principles

Buyer is responsible for planning the way it chooses to use any Capacity or Energy delivered pursuant to one of the Resource Summary Attachments governed by this Exhibit. As a part of the Wholesale Power Supply Agreement, the Parties have agreed to a set of Resource Summary Attachments that collectively are intended to represent a financial approximation of an allocation of the NCEMC Committed Resources on the Effective Date.

2.	For any hour of delivery, Seller will optimize resources around final dispatch for the combined load of all of Seller’s Participating Members, plus the schedules of the Buyer and other Independent Members.

3.	Buyer will pay Seller charges for Energy and the delivery of Energy to the Interface Point under terms specified in Resource Summary Attachments and terms specified elsewhere in this Agreement including but not limited to Sections 2.4, 2.12 and Article Five.

Delivery of Allocated Resources

4.	Energy Scheduled from Buyer’s Independent Member Allocation is delivered to the Interface Point. The cost and expense of all transmission services, including ancillary services and losses, from the Interface Point are the sole responsibility of Buyer.

5.	Seller will be deemed the provider of the resources needed for the purposes of tagging and for the designation of resources under the applicable tariffs of the Transmission Provider(s) selected by Buyer.

Scheduling by Buyer

6.	All Schedules from Buyer for each Independent Member Allocation will be in whole MWs and may not exceed the IM Allocation MW detailed on the Resource Summary Attachment.

7.	Buyer will submit a separate Schedule in conformance with this Exhibit S by System by resource up to the Maximum Scheduling Limit by System, as further described in Paragraph 23 of this Exhibit S.

8.	Buyer will be responsible for scheduling and arranging for the delivery of its SEPA allocation.

- 2 -

For any Independent Member Allocation that is designated as producing Must-Take Energy, Buyer is required to Schedule for every hour of every day of the Delivery Period its full Must-Take Energy obligation from such a resource, and may not amend or reduce its Schedule for that Energy: provided, however, that to the extent that Seller’s obligation to purchase Must-Take Energy from a resource designated as producing Must-Take Energy is reduced in any hour, Buyer’s hourly Must-Take Energy obligation shall be adjusted by the ratio of Seller’s hourly Must-Take Energy obligation to the Resource Capacity, rounded to whole MWs. The Buyer shall not be entitled to Schedule Must-Take Energy in an hour in amounts, which exceed the Buyer’s adjusted Must-Take Energy obligation for that hour.

10.

Buyer is obligated to Schedule resources in accordance with the terms and conditions provided in the Resource Summary Attachments consistent with the minimum run times in the contracts pertaining to Seller’s purchased and/or owned resources, and Seller will use its good faith efforts to accommodate Buyer’s Schedules that do not meet the minimum run time requirements, but only so long as meeting such non-conforming Schedules would not likely result in additional costs to Seller or any of its Participating Members.

11.	Except with respect to Buyer’s Independent Member Allocations that supply Must-Take Energy, Buyer is not obligated to Schedule its Independent Member Allocations consistent with the minimum volumes in the power supply contracts of Seller that are in force on the Independent Member Effective Date.

12.	By 7:00 a.m. EPT each day Buyer must provide Seller with an hourly forecast of its load by System for the following day.

13.

The Buyer may Schedule its resources consistent with the table below. Day-ahead Schedules are those submitted before 8:00 a.m. EPT the day prior to flow. Intra-day Schedules are those that are requested after the 8:00 a.m. EPT deadline above. All Schedule changes must occur at the top of the hour. Intra-day Schedule changes require two (2) hours advance notice.


Scheduling Changes
Day Ahead		Intra-Day

Unlimited changes up to the IM Allocation MW identified in the Resource Summary Attachment for each resource in whole MWs.		Up to two changes to the hourly Schedule for the remainder of the day. Each change to the hourly Schedule shall be no greater than 5%, for a cumulative maximum of 10% each hour. Additional changes will be accommodated on a best efforts basis.

- 3 -

Scheduling by Seller

14.	Seller is not obligated to meet Buyer’s final Schedule using the NCEMC Committed Resources associated with the Independent Member Allocations Scheduled by Buyer.

15.	Seller will accept the risk and/or benefit resulting from differences in the cost of resources used to provide Buyer Energy in accordance with its Schedule(s), and the costs Seller would have incurred had it used NCEMC Committed Resources to meet Buyer’s Schedule of the Scheduled resource(s).

16.	Should Seller acquire an alternate resource, rather than use an NCEMC Committed Resource to serve Buyer’s Schedule, and that alternate resource is curtailed, Buyer’s Schedule will be maintained and any penalty, benefit or curtailment will be borne by Seller.

17.

Should all or any portion of NCEMC Committed Resources that have been Scheduled by Seller and Buyer to meet Buyer’s Schedule in any given hour be interrupted, then Seller shall try to identify available alternate resources which Seller, in its sole discretion, determines are reasonably priced and suitable to meet Seller’s needs. If Seller determines that such alternate resources are available, Seller may maintain the Scheduled deliveries to Buyer but at a price to be determined by Seller and communicated to Buyer. If no alternate resources are available to Seller, Buyer’s Schedule will be curtailed. All damages recovered by Seller from the Person responsible for the interruption in service will be shared with Buyer and every other Member similarly affected by such interruption in service.

Operations and Planning

18.	Buyer will provide Seller with a real time telemetered signal of Buyer’s load for Seller’s use, for purposes of determining when to start and stop the dynamic schedule, and to Schedule certain Must-Take Energy requirements of NCEMC Committed Resources.

19.

Seller shall provide and inform the Buyer on each Thursday by 1:00 p.m. EPT of the projected amount of Energy available hourly by Independent Member Allocation by System for Scheduling by Buyer for the following Saturday through Friday period, including the amount of Must-Take Energy that will be delivered and must be taken hourly.

20.

By 8:00 a.m. EPT each day, Buyer shall provide an hourly forecast of its Native Load by System for the next seven (7) days. For purposes of this Exhibit S, “Native Load” shall mean only the load of Buyer’s members. This load forecast will be used by Seller to calculate the hourly Energy available from the Independent Member Allocations that are available to be Scheduled for a given interval of time.

21.	Buyer shall provide Seller on each Thursday by 4:00 p.m. EPT, a projected hourly Schedule of all the Independent Member Allocations governed by this Agreement for the following Saturday through Friday period.

- 4 -

22.	Seller and Buyer agree on the following checkout and verification process:

As soon as practical after midnight, confirm hourly Schedules, energy flows and energy charges by resource and daily totals;

Provide a contact person each Business Day for the following:

Resolve issues that remain unresolved;

Perform month-to-date confirmations of hourly Schedules, energy flows and energy charges by resource and daily totals;

Finalize monthly checkouts by the second Business Day of the following month; and Coordinate any true-ups that may be required.

23.

For Buyers having loads in more than one System, Buyer will provide at the Independent Member Election Date and on July 1of each subsequent year, a forecast of the percentage of its retail load in each System. (The sum of the percentages must equal 100%). The Maximum Scheduling Limit by System for the following calendar year will be calculated by multiplying the percentage of Buyer’s retail load in each System times the total of Buyer’s Independent Member Allocations for the following calendar year.

- 5 -

Attachment 8-1

(Part II of II)

TERMS AND CONDITIONS

FOR OBTAINING TRANSMISSION

SERVICES ADEQUATE TO DELIVER

FROM THE INTERFACE POINTS

ESTABLISHED UNDER THE

WHOLESALE POWER SUPPLY AGREEMENT

OF NCEMC FOR SALES TO

ITS INDEPENDENT MEMBERS

- 6 -

General Principles and Responsibilities for Transmission : All Resource Summary Attachments associated with the Wholesale Power Supply Agreement between Seller and Buyer are governed by and subject to the terms and conditions in this Exhibit unless a specific Resource Summary Attachment explicitly provides otherwise. For purposes of this Exhibit, the Wholesale Power Supply Agreement and each Resource Summary Attachment governed by this Exhibit, the term “Acceptable Transmission Service” means the level of service available at any point in time that is equal to or better than that level of service currently defined as “Network Integration Transmission Service” under the Open Access Transmission Tariff of the System to which Buyer’s distribution system is physically interconnected, and if connected to more than one System, then Buyer must have Acceptable Transmission Service for each Interface Point.

The following terms for transmission service apply to each Resource Summary Attachment included as a part of this Agreement. All of these terms assume that the current Open Access Transmission Tariff environment in force on the Effective Date remains in force, without modification or amendment. The Parties hereto agree that any amendment, modification or change to that tariff or the regulatory environment for the wholesale electric industry, whether by regulation, regulatory action, statute, judicial action, executive decision or order, or otherwise, may require modification of this Exhibit to restore to Buyer and Seller the benefits that each intended. Such amendments, modifications or changes would include, without limitation, any changes or modifications of the wholesale electric industry environment based on the Standard Market Design, or the restructuring of the transmission systems or the regulatory oversight of same. If the Parties fail to reach agreement on modifications of this Exhibit, the dispute shall be subject to arbitration under the Wholesale Power Supply Agreement.

Buyer is responsible for planning for and scheduling the receipt of capacity and energy to be delivered to Buyer. Buyer will be responsible for negotiating, making and keeping in force one or more transmission agreements with the Transmission Provider(s) necessary to perform its obligations under the Wholesale Power Supply Agreement. At a minimum, Buyer will negotiate, make and keep in force its own Network Integration Service Agreement (“NITSA”) and its own Network Operating Agreement (“NOA”).

Subject to and contingent upon the concurrence and agreement of each affected Transmission Provider, the RUS, and the Federal Energy Regulatory Commission (“FERC”), the Parties further agree:

1.	Buyer is responsible for serving its own load. It will do so through contracts with Seller, along with other resources Buyer will acquire.

2.	Buyer will have its own transmission agreement(s) with each and any Transmission Provider(s) whose services are needed to move capacity or energy from any Interface Point of the System(s) to which Buyer’s distribution system is physically interconnected.

3.	Buyer will negotiate its own NITSA and NOA. Seller will provide assistance with these negotiations as requested. The cost for this assistance will be charged to Buyer separately from charges for Capacity and Energy billed under Article 5.1 of this Agreement.

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4.	Seller will transfer the direct-assigned facilities used for that Buyer, if any, to Buyer’s NITSA once the same has become effective.

Seller will provide Buyer with contractual rights that financially approximate the hypothetical assignment of a total amount of Seller’s owned and/or purchased resources, calculated in accordance with the NCEMC Member Power Supply Resource Policy, for purposes of Buyer’s NITSA and NOA designations for energy delivered to the System served by the Transmission Provider with which Buyer has entered its NITSA and NOA.

If any need exists or arises to designate, in addition to the contracts with Seller, any other network resources in order to meet Buyer’s load in accordance with the tariffs or other requirements of the Transmission Provider(s), Buyer has the responsibility to locate, identify and designate such other network resources.

7.	Buyer will have the obligation to satisfy the requirements of the applicable OATT, and purchase or self-supply, as applicable, any ancillary or other services needed or required to serve its load.

Buyer will coordinate with Seller or its scheduling agent under Exhibit S to this Wholesale Power Supply Agreement to assure that the proper schedule is in place each day for Buyer’s scheduled amount of Energy related to each of Buyer’s Resource Summary Attachments that are governed by this Exhibit.

In addition to the other responsibilities arising under this Exhibit, Buyer shall be solely liable for any energy imbalance settlement and any other settlements or liabilities to which a Transmission Customer is exposed at and from the Interface Point(s). If Buyer causes Seller to incur energy imbalance charges, Buyer will reimburse Seller for any charges that Seller incurs.

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PARTIAL REQUIREMENTS SERVICE AGREEMENT

BETWEEN

DUKE POWER COMPANY LLC

d/b/a DUKE ENERGY CAROLINAS, LLC

AND

RUTHERFORD ELECTRIC MEMBERSHIP CORPORATION

DATED AS OF MAY 12, 2006

TABLE OF CONTENTS


		Page
Article 1 Definitions		2

1.1	Definitions.	2

1.2	Interpretation.	20

1.3	Construction.	20

Article 2 Term		21

2.1	Effectiveness.	21

2.2	Term.	21

2.3	Termination.	22

2.4	Absolute Nature of Termination.	27

Article 3 Conditions Precedent to the Commencement Date		27

3.1	Conditions Precedent to Duke’s Obligations.	27

3.2	Conditions Precedent to EMC’s Obligations.	28

3.3	Notice of Satisfaction of Conditions Precedent.	29

3.4	Waiver of Condition Precedent.	29

3.5	Commencement of Service; Failure of Condition Precedent.	30

Article 4 Sale of Electric Capacity and Energy		34

4.1	Classification of Services Provided.	34

4.2	FFR Supplemental Service.	34

4.3	Partial Requirements Service.	37

4.4	Excepted Load.	38

4.5	Good Title.	38

4.6	Power Quality.	38

Article 5 EMC Resources		39

5.1	EMC Contract Resources (Commencement Date - December 31, 2010).	39

5.2	EMC Contract Resources (January 1, 2011 - Termination of Agreement).	40

5.3	No Duke Obligation for Customer Resources.	43

5.4	New Customer Resources.	43

Article 6 Priority of Service		44


6.1	Interruption of FFR Supplemental Service and Partial Requirements Service.	44

6.2	Curtailments of Load.	44

6.3	Emergency Load Curtailment Program.	44

6.4	Substitute Energy.	45

6.5	Substitute Energy Costs.	45

Article 7 Capacity and Energy Charges		45

7.1	Charges During Commencement Date - December 31, 2006.	45

7.2	Charges During January 1, 2007 – December 31, 2010.	50

7.3	Charges Commencing January 1, 2011.	51

7.4	Monthly Reserve Capacity Charges.	53

7.5	Payment.	54

7.6	Determination of EMC Capacity and Energy Demands.	54

Article 8 Scheduling Agent Services		55

8.1	Appointment of Duke as Scheduling Agent.	55

8.2	Scheduling Policies.	55

8.3	Protocols.	55

8.4	Scheduling Agent Services (Commencement Date through December 31, 2010).	55

8.5	Scheduling Agent Services (January 1, 2011 through Termination).	56

8.6	New EMC Resources.	57

8.7	Errors in Schedules	57

8.8	EMC Responsibilities	57

8.9	Duke’s Liability	58

8.10	Termination Assistance Service	58

Article 9 Transmission and Ancillary Services		58

9.1	Delivery Obligations	58

9.2	Transmission Arrangements	58

9.3	Ancillary Services	58

9.4	Regional Transmission Organization	59

Article 10 Operating Committee		60

10.1	Operating Committee	60

10.2	Duties of the Operating Committee	60


Article 11 Demand Side Management		60

11.1	Availability of Demand Side Management Resource Programs	60

11.2	Changes to Demand Side Management Resource Programs	60

11.3	Credits	61

11.4	Necessary Arrangements	61

11.5	Start-Up Conditions	61

11.6	Periodic Testing	61

11.7	EMC Demand Side Management	62

Article 12 Modification of This Agreement		63

12.1	Unilateral Modification	63

12.2	Mobile-Sierra Public Interest Standard	63

12.3	Changes To Certain Charge Components	63

12.4	Standard of Review for Permitted Changes	64

12.5	Scope of Waiver	64

Article 13 Billing and Payment		64

13.1	Billing Period	64

13.2	Billing Statements.	64

13.3	Timeliness of Payment	65

13.4	Netting of Payments	65

13.5	Disputes and Adjustments of Statements	65

13.6	Records and Audits	66

Article 14 Dispute Resolution		68

14.1	Arbitration	68

14.2	Negotiation and Notice of Arbitration	68

14.3	Individual, Joint or Consolidated Arbitration	68

14.4	Selection of Arbitration Process	69

14.5	Initiation of Arbitration.	70

14.6	Arbitration Processes.	70

14.7	Decision	73

14.8	Expenses	74

14.9	Effect of Dispute Resolution Procedures	74


14.10	Confidentiality	74

Article 15 Credit and Collateral Requirements		74

15.1	Posting of Collateral	74

15.2	Material Adverse Changes	74

15.3	Continuing Nature of Collateral Requirement.	75

15.4	Interest on Cash Used as Collateral	75

15.5	Grant of Security Interest/Remedies	75

15.6	Notice, Information	76

15.7	Definitions.	76

Article 16 Additional Terms		78

16.1	Representations Warranties and Covenants.	78

16.2	Assignment.	81

16.3	Liability and Indemnification.	82

16.4	Force Majeure	83

16.5	Events of Default and Remedies.	84

16.6	Confidential Information.	86

16.7	Governmental Liabilities.	87

16.8	Choice of Law	88

16.9	Survival of Obligations	88

16.10	Entire Agreement	88

16.11	Cost Projections	88

16.12	Unique Agreement	89

16.13	No Transfer of Rights	89

16.14	No Partnership	89

16.15	Third Parties	89

16.16	Waiver	89

16.17	Time of Essence	89

16.18	Headings	90

16.19	Severability	90

16.20	Counterparts	90

16.21	No Public Announcement	90


16.22	Notices	90

16.23	No Dedication of the System	91

16.24	Stranded Costs	91

16.25	Electric Peak Load and Energy Information to be provided by EMC	92

16.26	Demand and Energy Charge and Rate Information to be Provided by Duke	92

16.27	Further Assurances	92

16.28	Applicable Laws and Regulations	92

16.29	Equitable Relief	92

16.30	PURPA Assistance	92

16.31	SERC and NERC Data Reporting and Compliance Assistance	92


		SCHEDULES

1		Annual Production Capacity and Energy Rates

		ATTACHMENTS

3-1		Calculation of the Excess Annual Capacity Charges in the Duke-Blue Ridge Agreement, Duke-Piedmont Agreement and Duke-Rutherford Agreement

4-1		EMC’s Base Obligation and Fixed Forward Resource

4-2		Calculation of Reduction to EMC’s Base Obligation and EMC Group’s Base Obligation During Light Load Periods

4-3		Partial Reqirements Resources

7-2		Calculation of the Monthly Demand Charges in the Duke-Blue Ridge Agreement, Duke-Piedmont Agreement and Duke-Rutherford Agreement

7-3		Calculation of Rutherford Allocated Share of Duke Total Hourly Energy Charge, EMC Group Total Hourly Energy Credit, Inter-EMC Energy Charge and Inter-EMC Energy Credit

7-4		Calculation of Blue Ridge, Piedmont and Rutherford Allocated Shares of the Duke Total Hourly Energy Charge, EMC Group Total Hourly Energy Credit, Inter-EMC Energy Charge and Inter-EMC Energy Credit

7-5		Example showing Calculations of Rutherford Energy Purchase Amounts and Rutherford Energy Credit Amount


7-6		Example showing Calculations of EMC Group Energy Purchase Amounts and EMC Group Energy Credit Amount

7-7		Example showing the calculation of Monthly Billing Demand under Section 7.2.2.2

7-8		Examples showing the calculation of Monthly Billing Demand under Section 7.3.2.2

7-9		Demand Rate Adjustment Percentage and Annual Percentage

7-10		Example of Demand Rate Adjustment Percentage and Annual Percentage

8-1I		Terms and Conditions for the Scheduling of Power Supplied by North Carolina Electric Membership Corporation to its Independent Members

8-1II		Terms and Conditions for Obtaining Transmission Services Adequate to Deliver from the Interface Points Established under the Wholesale Power Supply Agreement of NCEMC for Sales to its Independent Members

8-2		SEPA Policies

PARTIAL REQUIREMENTS SERVICE AGREEMENT

BETWEEN

DUKE POWER COMPANY LLC

d/b/a DUKE ENERGY CAROLINAS, LLC

AND

RUTHERFORD ELECTRIC MEMBERSHIP CORPORATION

THIS PARTIAL REQUIREMENTS SERVICE AGREEMENT, dated as of May 12, 2006, is entered into by and between Rutherford Electric Membership Corporation, a corporation organized and existing under Article 2 of Chapter 117 of the General Statutes of North Carolina, together with any permitted successor or assignee (“EMC” or “Rutherford”), and Duke Power Company LLC, d/b/a Duke Energy Carolinas, LLC, a limited liability company organized and existing under the laws of North Carolina, together with any permitted successor or assignee (“Duke”). Hereinafter, Duke and EMC are sometimes also referred to individually as a “Party” or collectively as the “Parties.”

W I T N E S S E T H

WHEREAS, EMC is a member of North Carolina Electric Membership Corporation (“NCEMC”) and is a party to the WPSA; and

WHEREAS, EMC is a party to the SEPA Contract; and

WHEREAS, EMC is a party to the PPA; and

WHEREAS, Duke and EMC have agreed to the terms and conditions upon which the sale of electric capacity and energy and provision of Scheduling Agent Services may be conducted between the Parties.

Article 1

Definitions

1.1 Definitions .

Defined terms in this Agreement are capitalized. The defined terms used in this Agreement have the following meanings:

“Accounting Requirements” shall have the meaning specified in Section 15.7.

“Administrator” shall mean the RUS Administrator.

“Adverse Ruling” shall have the meaning specified in Section 3.1(c).

“Agreement” means this Partial Requirements Service Agreement, together with each Schedule and Attachment, each as amended from time to time.

“Annual Capacity Factor” shall have the meaning specified in Section 4.3.3.1.

“Annual Capacity Price” shall have the meaning specified in Section 3.5.2.3.1, 3.5.2.3.2 or 3.5.2.3.3, as applicable.

“Annual Capacity Quantity” shall have the meaning specified in Sections 3.5.2.3.1, 3.5.2.3.2 or 3.5.2.3.3, as applicable.